On Track for a Golden Age of Gas?

• The global energy industry must overcome significant new challenges if natural gas development is to achieve the vision of a Golden Age of Gas.
• Low energy prices and reduced investment are only half the battle as regulations complexify and organized opposition grows. 

Five years ago the International Energy Agency (IEA) issued a report entitled, "Are We Entering a Golden Age of Gas?" Gas development was booming, from both conventional resources and US shale deposits, and gas was widely seen as a vital tool for reducing greenhouse gas emissions. Much has happened since then, including a collapse in global oil prices, the signing of a new climate agreement in Paris, and a broadening of the anti-fossil-fuel focus of climate activists. If we're still on the path to a golden age of gas, the ride will be bumpy.

This is probably most evident across the pond, where Nick Butler, the Financial Times' respected energy analyst, observed this week, "Unless something changes radically, Europe has passed the point of peak gas consumption." He cited Germany's ongoing "Energiewende" (energy transition) which in order to maximize wind and solar and minimize nuclear power, ends up squeezing gas out between renewables and much higher-emitting coal.

Earlier this month France's Energy Minister announced she was pursuing a ban on imports of US shale gas--effectively any gas from the US--since France already bans domestic fracking. That strikes me as a textbook example of having to keep making bad decisions to be consistent with the first one, but it's their sovereign choice.

As the IEA defined it at the time, this Golden Age would entail faster growth in gas demand in every major sector, compared to the agency's main "New Policies" scenario in its then-current annual World Energy Outlook (WEO). They anticipated compound average growth of 1.8% per year, much faster than oil or coal, with gas consumption ending up 13% higher than the WEO's projection for 2035. That's like adding an extra Russia or Middle East to world gas demand within 20 years.

One gauge of whether that still seems realistic can be found in the US Energy Information Administration's (EIA) just-released 2016 International Energy Outlook. The EIA's long-term forecast actually has gas consumption growing slightly faster than IEA's Golden Age track in the developed countries of the OECD between now and 2035, but with a slower ramp-up to essentially the same end-point in the non-OECD countries.

Of course one forecast can't really validate another, so let's consider how some of the big uncertainties that the IEA identified in the 2011 report have shifted, starting with energy pricing. After oil's recent rebound, oil and gas have fallen by around half their 2011 US prices. That makes investments in oil and gas exploration and production considerably less attractive. Nearly $400 billion of projects have been canceled or deferred, globally, setting up slower growth in production from both gas fields and oil fields with associated gas in the near-to-medium term. This deceleration is evident in EIA's latest monthly Drilling Productivity Report for US shale.

With the contract price of liquefied natural gas (LNG) often tied to oil prices or competing with pipeline gas that has also fallen in price, large gas infrastructure projects like LNG plants look less attractive, too. We've already seen cancellations of new facilities in Australia and Canada. Fewer LNG export facilities are likely to be built in the US than previously planned. All this means less new gas reaching markets where it can be used.

Cheaper oil also reduces the attractiveness of gas as a transportation fuel. Although increasingly popular as a cleaner fuel for buses, natural gas hasn't made much headway in US passenger cars. However, this application has been growing in places like Italy and Iran, for different reasons.

Viewed in isolation, these price-related responses seem likelier to delay, rather than derail the expectations the IEA set out in 2011. The bigger challenges come from a set of issues the IEA identified a year later, in a follow-up report called "Golden Rules for a Golden Age of Gas." As Dr. Birol, now the Executive Director of IEA, indicated then, these boil down to the industry's "social license to operate."

Transparency, water consumption, emissions including methane leaks--all on IEA's list--are some of the key issues over which companies, regulators, NGOs and activists are sparring today. The UK is a prime example. Conventional energy production is declining rapidly and a large shale gas potential has been identified by the British Geological Survey, but every attempt to drill exploratory wells has encountered strong opposition.

A new factor the IEA did not anticipate is the emergence of political movements focused on fossil fuel divestiture and a "keep it in the ground" mantra. These may be based on unrealistic expectations of how quickly the world can transition to a zero-emission economy, but they illustrate the scale of a stakeholder engagement challenge the global oil and gas industry has so far failed to meet adequately. 

Just as social media are transforming politics, they are also altering the balance of power between organizations and their critics. The gaps that must be bridged if new gas development is to remain broadly acceptable to the public are growing in ways that will demand new approaches and new strategies to address. 

Considering the shifts in the global energy mix that will be necessary to reduce global emissions in line with the goals of last year's Paris Agreement, gas ought to have a future every bit as bright as the Golden Age the IEA described five years ago. Achieving that now likely depends less on the price of energy and the scale of available resource than on convincing regulators and the public that the trade-offs involved in obtaining its benefits are still reasonable.

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.





 

The Missing Oil Crisis of 2014

• While the full impact of the surge in US "tight oil" may be masked by problems elsewhere, it is on the same scale--but opposite direction--as key factors that led to the 2007-8 oil price spike.
• In that light it does not seem like hyperbole to credit the recent revival of US oil output with averting another global oil crisis.

Several speakers at last month's annual EIA Energy Conference in Washington, DC reminded the audience that energy security extends beyond oil, starting with Maria van der Hoeven, Executive Director of the International Energy Agency (IEA). In her keynote remarks Monday morning she was quick to point out that it also encompasses electricity, sustainability, and energy's effects on the climate and vice versa. Still, the comment that got my wheels turning came from Dan Yergin, author and Vice Chairman of IHS. During his lunch keynote he suggested that without US tight oil production, this year's conference would have been dominated by another oil crisis.

Although shale energy development certainly deserves to be called revolutionary, crediting it with averting an oil crisis calls for a bit of "show me." Yet with problems in Libya, Nigeria and Iraq, while Iranian oil remains under sanctions and oil demand picks up again, even at first glance Mr. Yergin's assertion looks like more than a casual, lunch-speech sound-bite.

Start with current US tight oil (LTO) production of over 3 million barrels per day (MBD) and estimates of future LTO production rising to as much as 8 MBD--also the subject of much discussion at the conference. As recently as 2008 total US crude oil output had fallen to just 5 MBD and was only expected to recover to around 6 MBD by 2014, with minimal contribution from unconventional oil. Instead, the US is on track to beat 2013's 22-year record of 7.4 MBD, perhaps by as much as another million bbl/day.

With conventional production in Alaska and California declining or at best flat, and with Gulf of Mexico output just starting to recover from the post-Deepwater Horizon drilling moratorium and subsequent "permitorium", the net increase in US crude production attributable to LTO today is in the range of 2.5-3.5 MBD and growing, thanks to soaring output in North Dakota, Texas and other states.

That might not sound like much in a global oil market of over 90 MBD, but it brackets the IEA's latest estimate of OPEC's effective unused production capacity of 3.3 MBD. Spare capacity and changes in inventory are key measures of how much slack the oil market has at any time. When OPEC spare capacity fell below 2 MBD in 2007-8, oil prices rose sharply from around $70 per barrel to their all-time nominal high of $145 per barrel. It took a global recession and financial crisis to extinguish that price spike, and high oil prices were likely a major contributor to the recession.

Global oil inventories are now a little below their seasonal average for this time of the year. Compensating for the absence of over 3 MBD of US tight oil would require higher production elsewhere, lower demand, or a drain on those inventories that would by itself push prices steadily higher.

Concerning production, if the US tight oil boom hadn't happened, more investment might have flowed to other exploration and production opportunities. However, for non-LTO production to have grown by an extra 3 MBD, companies would have had to invest--starting in the middle of the last decade--in the projects necessary to deliver that oil now. Were that many deepwater and conventional onshore projects deferred or canceled because companies anticipated today's level of LTO production more than 5 years ago? And would Iraq, Libya and Nigeria be more reliable suppliers today if US companies hadn't been drilling thousands of wells in shale formations for the last several years? Both propositions seem doubtful.

As for adjustments in demand, US petroleum consumption is  already over 8% less than in 2007. And as we learned in the run-up to 2008, much of the oil demand in the developing world, where it has grown fastest, is less sensitive to changes in oil prices than demand in developed countries, due to high levels of consumer petroleum subsidies in the former. Petroleum product prices in the latter must increase significantly in order to get consumers there to cut their usage by enough to balance tight global supplies. That dynamic played an important role in oil prices coming very close to $150 per barrel six years ago, when average retail unleaded regular in the US peaked at $4.11 per gallon, equivalent to nearly $4.50 per gallon today.

So to summarize, if the US tight oil boom hadn't happened, it's unlikely that other non-OPEC production would have increased by a similar amount in the meantime, or that OPEC would have the capability or inclination to make up the resulting shortfall versus current demand out of its spare capacity. Demand would have had to adjust lower, and that only happens when oil and product prices rise significantly. With oil already at $100 per barrel, it's not hard to imagine such a scenario adding at least $40 to oil prices--just over half the 2007-8 spike. Combined with higher net oil imports, that would have expanded this year's US trade deficit by around $230 billion. US gasoline prices today would average near $4.60 per gallon, instead of $3.54, taking an extra $140 billion a year out of consumers' pockets.

We can never be certain about what would have happened without the current surge in US tight oil, but for a reminder of how a similar situation was characterized just a few years ago, please Google "2008 oil crisis".  If we found ourselves in similar circumstances today, then the heated Congressional hearings and angry consumers to which Mr. Yergin alluded in his remarks would almost certainly have been major topics at EIA's 2014 conference, instead of the realistic prospect of legalized US oil exports.

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

Comparing Driving Costs of EVs and Conventional Cars

• A new Department of Energy website helps consumers compare the energy costs of EVs to non-plug-in cars by converting kilowatt-hours into "eGallons".
• How valid this proxy is depends heavily on assumptions about the cars being compared to EVs.  If hybrids set the bar, then DOE's eGallon prices are significantly understated.

I’ve been looking through a new website developed by the US Department of Energy (DOE) to assist consumers in comparing the energy costs of driving an electric vehicle (EV), relative to posted gasoline prices in their state. I heard about this site at the US Energy Information Administration’s (EIA) annual energy conference in Washington, DC last month. It sounded like a handy tool for both current EV owners and those considering buying one, but I couldn’t help thinking about it in the context of a presentation I saw at the same conference on the cost effectiveness of federal tax credits for EV purchases. A key question in both instances concerns just what kind of car is being replaced by that new EV.

The website uses simple math, together with the EIA’s continuously updated data on gasoline and electricity prices around the country, to come up with a national and state-by-state price for an “eGallon”. This imaginary construct is essentially the quantity of electricity that would take a typical EV as far as a gallon of gasoline would take the average new conventional car. As the text points out, it’s hard for consumers to calculate this for themselves. They see gasoline prices everywhere they drive but must dig through their utility bills to find their electricity price–not always obvious–and then might not know how to compare the two.

The site’s documentation indicates the eGallon calculation is based on the average energy usage of five specific EVs, including the Chevrolet Volt, Nissan Leaf, and Ford Focus EV, along with the 2012 EPA fleet average fuel economy for what EPA defines as small and mid-size cars. The result is side-by-side postings of the US average gasoline and eGallon prices, plus a drop-down menu to replicate that for each state. The site also includes the chart below, comparing these two prices over the last decade.

Two facts become immediately apparent. First, electricity is generally a cheaper fuel for cars than retail gasoline. That’s true for a variety of reasons, including the higher end-use efficiency of electric motors compared to internal combustion engines and the lower cost of most of the fuels used to generate electricity in the US. For example, the natural gas burned in power plants sold for the equivalent of $ 20.40 per barrel last year, while the global benchmark for oil averaged nearly $112/bbl. It also appears to be less volatile, at least at the level of national averages.

However, just as there’s no single gasoline price for the whole country, neither is there a single electricity price. Even the state averages used by the DOE to calculate eGallon prices mask a bewildering variety of regional electricity price tariffs and tiers. So your cost to recharge an EV might not just vary by location, but by time of year, time of day, and the specific rate plan that applies to you.

My main concern about the site derives from something much simper: the big central assumption that EVs compete with the average cars sold in America last year. According to the eGallon site, the average small-to-medium US car in 2012 got 28.2 miles per gallon (mpg) in combined city and highway driving. Using that figure, and with residential US electricity prices averaging 11.6 ¢/kilowatt-hour (kWh) in March 2013, the national eGallon price for March would have been $1.14/gal., compared to $3.71/gal. for unleaded regular gasoline. But what if we assumed that the cars most often compared to a new EV were not average cars, but other efficient cars, as logic and my intuition suggest? If we substituted the fuel economy data for a conventional Ford Focus or Toyota Prius hybrid, the eGallon price would jump to $1.26 or $2.03, respectively.

In some respects this result is fairly obvious. If you were already contemplating buying a hybrid, an EV won’t save you as much as if you were thinking of buying a conventional mid-size sedan. However, this distinction is important enough that the DOE should consider refining its eGallon calculator. EVs are much like wind and solar installations that cost more than conventional alternatives, but are expected to produce over their lifetimes economic or environmental benefits that offset those higher costs. The attractiveness of that big up-front investment is directly proportional to those benefits. I don’t have the data that would clarify the actual comparisons EV buyers are making, but someone must, perhaps including DOE. And it turns out that this isn’t just important for calculations like eGallon, but also for assessing the cost-effectiveness of federal EV policy.

That brings me to the Congressional Budget Office’s analysis of federal EV tax credits last fall. The report merits a posting of its own, but one nugget I gleaned from the presentation at the EIA Conference was that the CBO found that the current federal credit of up to $7,500 per car was still insufficient to make most EVs cost-competitive on a full-life basis with conventional cars. Yet despite this, the effective cost to taxpayers of each gallon of gasoline saved by a Leaf-type EV was well over $6 when compared to conventional cars getting average fuel economy, and over $10 vs. high fuel-economy compact cars. That’s assuming they save any gas at all, because of the way the Corporate Average Fuel Economy rules have been structured. Implied costs for greenhouse gas emissions avoidance were even more startling, at over $400/ton of CO2 in most cases.

The desirability of a tool like “eGallon” is rooted in the convoluted way we talk about transportation fuel economy and energy costs in this country. Miles per gallon is itself a poor metric, compared to something like gallons per 100 miles, or even miles per dollar. That's because it obscures the high value of modest improvements in high-consumption vehicles, while exaggerating the value of shifting from very efficient to ultra-efficient cars. It’s also more useful for policy makers than consumers, who are ultimately concerned about outcomes in dollars per mile or dollars per trip.

Recognizing the impracticality of training 300 million consumers to think about this subject differently, eGallon might prove useful, but only as long as it is grounded in the best information we have about the vehicle choices that potential EV buyers are actually considering. Since current EV incentives apparently provide a poor return to taxpayers, an overly simplistic tool that drives consumers too far in that direction might be worse than not having such a tool at all.

A different version of this posting was previously published on Energy Trends Insider.

Global Shale Oil and Gas Estimates Expand

• The Department of Energy's revised shale resource estimates shed new light on the global extent of shale gas and especially shale oil potential.
• While in the US shale gas preceded large-scale shale oil development, other countries may find fewer obstacles for the latter, and an eager market.

Recently revised estimates of global shale oil and gas resources from the Energy Information Administration (EIA) of the US Department of Energy represent a significant increase over the EIA's 2011 estimates.  Technically recoverable shale oil (tight oil) grew more than tenfold, due to the inclusion of formations outside the US, while estimated global shale gas resources rose by 10%. With these revisions, shale formations now constitute 10% of global crude oil resources and nearly a third of global natural gas resources, although the actual impact of these resources on production and markets is still likely to vary greatly from region to region and country to country.

This year's report reflects a greater focus on tight oil, incorporating insights from the significant development of US tight oil resources that has occurred since the previous report was published. Tight oil development is largely responsible for the 19% increase in US crude oil production from 2010 to 2012.  The smaller adjustment to shale gas is the net result of downward revisions for some countries assessed in 2011, such as Poland and Norway, together with the inclusion of resources in additional shale formations and countries, including Russia, Indonesia and Thailand.

The EIA and the consulting firm that prepared the report were careful to differentiate the technically recoverable resources (TRRs) identified in this data from the more restrictive categories of economically recoverable resources and proved reserves. In other words, these figures represent the quantities of oil and gas that could be recovered if prices justified development and infrastructure was available to carry them to market, not the amounts that producers currently plan to develop.  At the same time, these estimates constitute only a small fraction--at little as 5-25%--of the oil and gas thought to be present in the assessed shale deposits.  Further improvements in technology could substantially increase future TRRs. 

It's interesting to note that although the US leads the world in production of both tight oil and shale gas, it ranks second and fourth, respectively, in global resources of these fuels.  The report also indicates that estimated US tight oil resources of 58 billion barrels (bbl) are more than double current proved oil reserves, which represent just under 7 years of current production.  That's significant, because a sizable fraction of the 139 billion bbls of US conventional unproved TRR--non-shale crude oil not currently included in proved reserves--sits in onshore and offshore areas currently off-limits to drilling. So shale provides a pathway for US oil production to sustain higher output than in the recent past, without having to overcome barriers such as those impeding development offshore California or in the Arctic National Wildlife Refuge. 

Or consider Russia, for which the report cites proved reserves equivalent to 21 years of production and slightly exceeding tight oil TRRs.  Russia possesses many of the factors conducive to shale development, including a large drilling fleet and an oil industry accustomed to drilling large numbers of wells, along with oil-transportation infrastructure. It remains to be seen whether Rosneft and other producers will choose to develop the Bazhenov shale and other deposits rapidly, to increase total output and exports, or more gradually, to offset declines in mature fields and maintain current production rates.

The EIA also reported 32 billion bbls of tight oil TRR in China.  Conventional reserves are comparable to those of the US, supporting current production less than half America's.  Without tight oil, China's economic expansion and the rapid growth of its vehicle fleet put it on track to displace the US as the world's largest oil importer within a few years.  China-based companies are seeking oil in Africa, South America and North America, so it's hard to envision them leaving their own shale resources undeveloped. 

The situation is more complicated for shale-rich OPEC members like Libya and Venezuela.  For example, aside from its current political instability, Libya has nearly 90 years of conventional oil reserves at its current OPEC quota of around 1.5 million bbl/day, before considering the 26 billion bbls of tight oil identified by the EIA.

On balance, the latest EIA shale resource assessment presents a wider and more realistic view of shale outside the US than in 2011. That includes tempering some of the previous report's enthusiasm for shale gas prospects in places like Poland, where few wells had been drilled until recently. The new element is the report's portrayal of the tight oil resource base as broad and deep, centered mainly on countries likely to be motivated to develop it. The shale gas revolution may be slow to spread globally, due to much-discussed differences in the conditions for development, compared to those in the US.  By contrast the development of shale oil, or tight oil, faces fewer obstacles and an eager market.

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

The Need for Reliable Energy Data

I'm back at my desk after some business travel, and the item in this morning's batch of news that caught my eye concerns the reliability of the oil industry data collected by the Energy Information Agency of the US Department of Energy. The article in today's Wall St. Journal (subscription may be required) described EIA's methods for tallying oil inventories and other industry data as "antiquated and out-of-date." Nor is the Journal the first to draw attention to this issue. Last year US News & World Report published a story that reached a similar conclusion as the Journal: the EIA doesn't have enough money in its budget to do both the work expected of it and improve its processes. Yet I can't help wondering whether the real issue we ought to be focusing on is improving the accuracy of the oil data, or getting the data for other, increasingly important energy sources up to at least the same level of timeliness, comprehensiveness and accuracy as those for oil.

Before writing this, I had a quick conversation with one of the experts at the American Petroleum Institute who is involved in reviewing and analyzing the weekly industry statistics API puts out to subscribers. Although gathered independently and on a voluntary, rather than government-mandated basis, API's reports generally reflect the same underlying data and sources as EIA's. The last time I was actually involved in submitting EIA/API data from an operating facility was in the early 1980s, when everything was faxed in and compiled manually. I was surprised to hear that some of the data still comes in that way, though most of it is apparently gathered electronically, either though electronic data interchange or via email. What he emphasized to me, though, was that regardless of how the data is actually assembled and reviewed, it actually represents an extremely accurate survey, covering something like 85-90% of the industry, with non-filers' results estimated from less frequent census-type reports. That's much more comprehensive than the sampling rate for many of the other economic statistics on which the market depends--and to which it sometimes reacts violently.

One of the problems with any such system involves how the information is used. As long as traders focus so keenly on week-to-week changes, rather than the totals, this will tend to amplify the impact of any errors that creep in. For example, in last week's EIA statistics, the entire US commercial inventory of crude oil stood at 344 million barrels, reflecting a 1 million barrel increase from the previous week. An error of just 2 million barrels in either direction--or 0.3% of the total--could have increased that inventory build to 3 million barrels or swung it to a 1 million barrel drop, with very different outcomes for oil prices. While it would be nice to think errors of that magnitude could be avoided entirely, should the market be so sensitive to such changes, knowing that no assessment like this can ever be made 100% accurate, no matter how precisely it is assembled?

While the system might lend itself to improvements such as requiring electronic data submission by all participants and adding more analysts to scrutinize the filings for errors and omissions, I suspect the more urgent priority is expanding its scope to encompass all of the energy sources on which we now depend. After all, when the current national energy information system was first devised petroleum-based fuels were essentially the whole game for transportation energy, while still accounting for a significant portion of the input to fossil fuel power plants. Today ethanol satisfies roughly 8% of US gasoline demand, and the 14-16 million barrels of inventory that the ethanol industry keeps on hand is the energy equivalent of about 7% of the 200-230 million barrels of gasoline and blending components the oil industry has at any point. Those percentages are mandated by law to grow significantly in the next decade, as biofuels displace petroleum products.

How much longer should we be satisfied with production and inventory data for biofuels that are weeks or months out of date, when we require accurate weekly updates on petroleum and its products? And consider that this picture will only become more complicated as an increasing proportion of our needs are satisfied by various renewable and distributed energy sources. If we can spend billions improving the management and storage of health data, wouldn't it be worth widening our net and spending an extra few million to get a better handle on the energy flows and stocks upon which the entire economy depends?