Can Solar Fill the Hydropower Gap During California’s Drought?

• Although the scale of California's conventional hydropower remains much larger than that of solar power, solar's rapid growth provides a meaningful contribution to the grid.
• Solar power can work nearly anywhere, but installing it where it's actually sunny much of the time pays big dividends.

After reading a San Jose Mercury article with the unwieldy title, “Drought threatens California’s hydroelectricity supply, but solar makes up the gap” I was intrigued enough to do a little fact-checking on state-level  electricity statistics. The article quoted the head of the California Energy Commission, who implied that solar power additions were sufficient to make up for any shortfall in hydro, historically one of the state’s biggest energy sources. My initial skepticism about that claim turned out to be largely unfounded.

Solar has been growing rapidly, especially in California, but even with nearly 3,000 MW of photovoltaic (PV) and solar thermal generation in place, it’s still well short of the scale of California’s 10,000 MW of hydropower dams, especially when you consider that the latter aren’t constrained to operate only in daylight hours. However, I also know better than to respond to a claim like this without checking the data on how much energy these installations actually deliver.

My first look at the Energy Information Administration’s annual generation data seemed to confirm my suspicions. In 2012 California’s hydropower facilities produced 26.8 million megawatt-hours (MWh), while grid-connected solar generated just 1.4 million MWh. However, when I looked at more recent monthly data, the mismatch was much smaller, due to solar’s strong growth in the Golden State. For example, in September 2013 California solar power generated 435 MWh, or nearly 24% of hydro’s 1.8 million MWh.

The potential drought benefits of solar stand out even more sharply when we compare the growth in solar generation to the change in output from hydro. Last year solar electricity in the state increased by 2.4 million MWh, compared to 2012, while hydropower fell by 2.3 million MWh. That added solar power won’t provide grid operators the same flexibility as the lost hydropower, because of its cyclical nature, but it is clearly now growing at a rate and scale that makes it a serious contributor.

I’d be remiss if I didn’t point out that solar in California is still nowhere near the scale of the state’s biggest electricity source, natural gas generation, which in 2013 produced over 100 million MWh, or 57% of the state’s non-imported electricity supply. Gas is also filling much of the roughly 18 million MWh shortfall left by the early retirement of Southern California Edison’s San Onofre Nuclear Generating Station last summer, and if the state’s drought worsens, gas will be the main backup for further declines in hydropower.

Yet solar’s growing contribution to the state’s energy mix provides a clear demonstration that while generous state and federal policies can make installing PV economically attractive nearly anywhere, it’s abundant sunshine like California’s that makes it a useful energy source, especially when drought conditions reduce the output of other, water-dependent energy supplies.

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

Early Retirement of US Nuclear Plants Is a Step Backward

• The early retirement of the San Onofre reactor complex could increase California's greenhouse gas emissions by up to 6 million tons per year.

• Together with other announced and plausible retirements, the loss of existing US nuclear capacity would more than offset new reactors now under construction, along with their contribution to emissions reduction. 

Last month Southern California Edison announced that the utility’s San Onofre Nuclear Generating Station (SONGS), consisting of half of California's nuclear generating capacity, will close permanently.  The facility had nine years remaining on its operating license. The plant’s two reactors were shut down for repairs in early 2012, and the Nuclear Regulatory Commission (NRC) still hadn’t approved the company’s plan to restart them, despite a protracted review. Although this event is less dramatic than the 2011 Fukushima accident in Japan, its ripples are likely to extend beyond California, where both the state’s electricity market and its greenhouse gas emissions will be adversely affected.

Before considering how the San Onofre closures will affect the nation’s nuclear industry and generating mix, let’s focus on California. While accounting for only 3% of the state’s 2011 generating capacity from all sources, the SONGS reactors typically contributed around 8% of the state’s annual electricity generation, due to their high utilization rates. That’s a large slice of low-emission power to remove from the energy mix in a state that is committed to reduce its emissions below 1990 levels.

How much emissions will increase following the shutdown depends on the type of generation that replaces these units. If it all came from renewable sources like wind and solar, emissions wouldn’t go up at all, but that’s impractical for several reasons. Start with the inherent intermittency of these renewables, and then compound the challenge by its scale. Even in sunny California, replacing the annual energy contribution of the SONGS units would require around 7,200 MW of solar generating capacity, equivalent to nearly 2 million 4-kilowatt rooftop photovoltaic (PV) arrays. That’s over and above the state’s ambitious “Million Solar Roofs” target, which was already factored into the state’s emission-reduction plans.

Grid managers from the state’s Independent System Operator indicated that in the near term much of the replacement power for SONGS will be generated from natural gas. Even if it matched the mix of 71% gas and 29% renewables added from June 2012 to April 2013, based on “net qualifying capacity”, each megawatt-hour (MWh) of replacement power would emit at least 560 lb. more CO2 than from SONGS. That’s an extra 4 million metric tons of CO2 per year, or 8% of California’s 2010 emissions from its electric power sector and almost 1% of total state emissions. If gas filled the entire gap, or if the natural gas capacity used was not all high-efficiency combined cycle plants, the figure would be closer to 6 million metric tons, equivalent to the annual emissions from about 1.5 million cars.

The SONGS shutdown brings to four the number of nuclear reactors that have been closed permanently this year, reducing the operating US nuclear power plant fleet to 100 units. Several other plants face severe challenges, including the ongoing legal battle over the “certificate of public good” for Vermont Yankee, strong local opposition to the Pilgrim unit on Cape Cod, and a hotly contested license renewal process for the two Indian Point units near New York City. The early retirement of San Onofre can only embolden the opposition to other nuclear plants.

A few years ago, when the nuclear power sector planned a large new-build program in the US, it seemed reasonable to assume that most existing plants would easily obtain 20- or 30-year license extensions, in line with well-established precedent. That would carry the bulk of the fleet into the 2040s and beyond. Meanwhile, new construction would add many gigawatts of new capacity and enable nuclear power to gain market share against coal and gas. However, between a recession that stalled the growth of US electricity demand and the low natural gas prices brought about by the combination of the same recession and the shale gas revolution, the economics of new nuclear power in the US have become tenuous. Some operators have even canceled relatively low-cost “uprate” projects to increase capacity at existing plants.

As part of its Annual Energy Outlook for 2013, the Energy Information Administration (EIA) of the US Department of Energy looked at various scenarios for nuclear expansion or retrenchment. In addition to the four reactor retirements announced this year, Exelon Corp. has already announced that its Oyster Creek plant in New Jersey will shut down in 2019, after 50 years of operation. If the two Indian Point units were also shut down, then total retirements since 2012 would reduce US nuclear generating capacity of 101,400 MW by more than the 5,580 MW combined capacity of the five new reactors currently under construction and scheduled to start up by late 2018. The difference of around 650 MW would likely be made up by natural gas.

Between now and 2020, despite the first new nuclear power plants in a decade coming on-line, nuclear’s contribution to our energy mix won’t grow by much, and may actually shrink. That will have consequences for consumers and for efforts to reduce greenhouse gas emissions. Retiring fully depreciated power plants that still have many years of potential operating life remaining, and replacing them with new generation of any technology, is bound to increase the cost of electricity in the markets where these plants have operated. And even if the net loss of nuclear capacity were directly replaced with high-reliability renewable generation such as hydropower or geothermal, that’s still that much renewable capacity not available to displace higher-emitting generation. Opponents of nuclear power may see that as progress, but it looks like a step backward to me.

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

"All of the Above" Must Be Weighted by Common Sense

• "All of the Above" is just a cliché if not tempered by an appreciation of the strengths and weaknesses of different energy sources, and a standard basis of comparison.
• Renewable energy is gaining market share, but fossil fuels--especially oil and gas--will play crucial roles in the energy mix for decades.

Last month, Real Clear Politics and API hosted an energy summit in Washington, DC entitled, “Fueling America’s Future”. It was intended to provide a quick overview of most of the key technologies and issues associated with an all-of-the-above energy strategy for the United States. Going through the highlights of the webcast gives me an opportunity to summarize my point of view for new readers of this blog. I’d sum that up as “All of the Above”, with asterisks for the proportions and situations that make sense.

This slogan, at least in the manner in which it has been espoused by politicians in both parties, has attracted fair criticism for being overly bland and safe. I suspect that critique reflects a general sense that our energy mix has always been composed of all of the above, or at least all of the technologies that were sufficiently proven and economic to contribute at scale at any point in time. However, as both our technology options and choice criteria expand, our understanding of the evolving energy mix is hampered by metrics and assumptions that are overdue to be revisited.

The summit’s first panel examined the technologies of the mix, in a “lightning-round” format of five minutes apiece. The panel covered oil, natural gas, coal, nuclear and renewables, led by wind power.

The interim CEO of the main US wind energy trade association, AWEA, cited his industry’s progress in reducing the technology’s cost, increasing the domestic content in its US value chain from 25% to 67%, and expanding its market penetration. Mr. Gramlich was also surprisingly forthright about wind power’s continued dependence on federal subsidies, a point to which I’ll return in future posts.

He began with a statistic indicating that wind power was #1 in new US electric generation capacity last year. This is more than just a talking point, but it calls for some refinement if we’re to see an accurate picture of the changing US electricity mix. When most generating facilities operated within a narrow band of expected utilization, say 60%-80% of the time, comparing their nameplate capacities like this was satisfactory. Exceptions such as “peaking” gas turbines that only operate a few dozen or hundred hours a year were never the recipients of targeted government incentives.

Now, however, our energy mix includes technologies with effective utilization rates, or “capacity factors”, ranging from as low as 10% for solar photovoltaic (PV) installations in cloudy northern locations, to roughly 90% for nuclear power. Wind comes in around 20-35%, depending on site and turbine size. In terms of their likely annual power generation, new natural gas facilities actually led new wind farms by roughly 2:1 last year.

Given the enormous and largely unanticipated natural gas renaissance in the US, that shouldn’t surprise anyone. In my first blog post over nine years ago I posed a series of questions, including whether we were on the verge of an energy technology breakthrough. I had in mind something involving renewable or nuclear energy, energy storage, or vehicle technology. The shale gas revolution was already starting to emerge from obscurity, but I, along with most other energy experts at the time, remained oblivious to it.

The new head of the American Natural Gas Alliance described gas as clean, abundant and affordable. At least the last two points should be uncontroversial by now, backed up by market prices and resource assessments. We tend to think of gas as a bridge fuel to a lower emission future, but I think we’ll increasingly hear it called a “foundation fuel,” as Mr. Durbin did.

The spokesman from the Solar Energy Industries Association accurately referred to solar as our fastest growing energy source, though he didn’t explain how it would grow from 0.1% of US generation last year to more than 1% by next year. He alluded to a plausible inflection point based on policy and innovation, but his enthusiasm that solar was expanding rapidly outside California and the Southwest ought to worry us.

Until PV prices fall much lower than they have, a surge of installations in places like Vermont and Wisconsin means that taxpayers and ratepayers are paying more than they should to make that happen. And the global competition and “survival of the fittest” he touted has mainly resulted, not from capitalism, but from dueling government incentives for solar, especially in Europe and Asia. I’m much more positive about solar than the above might suggest, but like other renewables, it will cost less and achieve more for us in locations with high-quality resources.

The discussion on oil was more globally focused, based on BP’s forecasts and annual Statistical Review. Contrary to the widespread view of oil’s continued dominance, it has been losing market share over the last 40 years — including the last 13 years in a row — and stands at its lowest market share in the US since at least World War II.  The representative from BP linked this performance to oil’s concentration in transportation fuel, where it has been squeezed out by efficiency, low economic growth (and to some extent biofuels, which got short shrift in the session). At the same time, the growth of North American production, another dividend of the shale revolution, puts increasing pressure on OPEC. I’ll come back to this dynamic in future posts.

Wind and solar aren’t the only, or even the biggest, renewables, despite the attention they receive. I was glad to see hydropower–often the forgotten renewable–represented on the panel, though I was disappointed by the absence of geothermal power. Both are more geographically constrained, yet have features that wind and solar could only wish for.  Hydro generated nearly 7% of US electricity last year from just 3% of US dams, with significant potential for growth through retrofitting unpowered dams. The Executive Director of the National Hydropower Association quoted Senator Ron Wyden (D-OR), the new chairman of the Senate Energy and Natural Resources Committee, as saying, “Hydro is back.” That could prompt some interesting discussions.

I’m glad I wasn’t there representing coal, which must surely be the least loved energy source today. It continues to grow globally, with US coal exports playing a role, but the domestic US story is a “decline narrative” as the VP of the National Mining Association described it. He managed to find a note of optimism in the more efficient coal power fleet that will remain after 68,000 MW of old capacity retires by 2020, under pressure from various regulations and competition from natural gas. Unfortunately, efficiency alone isn’t sufficient. From my perspective, carbon capture and sequestration (CCS) is the key to reconciling coal’s convenience and low energy cost with its high emissions. CCS wasn’t mentioned by name, but was only alluded to as “technology that does not exist.” That dismisses it too lightly, as I’ll explain when time permits.

The head of government affairs for the Nuclear Energy Institute spoke last in the lightning round on technology. (The subsequent panel on energy issues is worth your time, too.) He emphasized nuclear’s anchor role in the US electricity mix, with 12% of US generating capacity contributing around 20% of the electricity supply at a cost of 2¢ per kilowatt-hour (kWh). Yet despite five new reactors under construction and a wave of license extensions, post-Fukushima the center of the nuclear industry is shifting to places like China and India. 66 reactors are under construction outside the US, mainly in the developing world, because that’s where demand is growing.

I’ve worked in various aspects of energy for more than 30 years, and for much of that time our energy mix and the forces that drive it have been in a state of flux. With that in mind, my recipe for “all of the above”  starts with what we have now, recognizes the inertia of existing fleets and infrastructure, and evolves as costs shift and our emphasis on environmental consequences grows.

Wind and especially solar will grow, but will add the most value when used with, rather than against the grain of their limitations. Nor will energy storage turn them into reliable, baseload energy sources like nuclear and coal, at least until it is much cheaper. The US natural gas opportunity looks transformative in a way that renewables don’t, yet, with value well beyond power generation. Coal will linger, but without effective CCS will remain vulnerable from many angles. Meanwhile, oil remains the indispensable fuel for transportation, which is the cornerstone of our global economy. Yet its indispensability will erode in increments each year, as EVs eventually grow from novelty to significance and new biofuels start to emulate oil’s trump cards of convenience and energy density. It’s a great time to be talking about energy, as it has been for the last nine years.

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

Can Energy Storage Make Wind and Solar Power As Reliable As Coal?

Wind and solar power generated 3.5% and about 0.1%, respectively, of US electricity last year.  These figures represent large increases from much smaller levels in the last decade as the cost of these technologies declined significantly, particularly for solar photovoltaic (PV) modules. However, other barriers to wider deployment remain, including their intermittent output.  Energy storage is often portrayed as the killer app for overcoming the intermittency of renewables, and a number of interesting developments have occurred on this front, including a new "hybrid" wind turbine with integrated storage from GE. To what extent could more and cheaper storage enable wind and solar to function as the equivalent of high-utilization, baseload generation? 

Assessing that potential requires, among other things, recognizing that energy storage is neither new nor monolithic. Nor is the intermittency of renewable energy a single challenge.  For example, the output of a wind turbine and the wind farm in which it operates varies on time scales of minutes, hours and days, as well as months and years.  The output of a PV installation varies somewhat more predictably, but no less dramatically. 

Generating companies and project developers have an array of new storage options, involving various battery technologies, flywheels, and compressed air. Pumped storage, in which water is pumped uphill and generates power later when it flows back downhill, is an old, though hardly obsolete option and already operates on a large scale. According to the National Hydropower Association the US has 22,000 MW of installed pumped storage. This, too, is expanding and remains one of the cheapest forms of power storage in terms of cost per megawatt-hour (MWh) delivered.   Enough new projects have received preliminary permits to more than triple that figure, in 23 states.

All of these storage alternatives have limitations or drawbacks.  Batteries and flywheels, while very responsive, are still expensive.  Compressed air storage often relies on unique local geological features, and some versions essentially function as a supercharger for a gas-fired turbine, resulting in some emissions. Pumped storage works well at a variety of scales but is less responsive than batteries, has a larger physical footprint, and requires suitable terrain. 

What makes GE's "brilliant turbine" with battery storage look clever is that, with the help of predictive models, it requires a very small amount of battery storage--perhaps as little as that in an electric car--to smooth the output of the turbine for 15 minutes to an hour. That provides significant benefits, including financial ones, in terms of integrating it predictably into the power grid. However, it doesn't transform the turbine into a fully dispatchable generator capable of sending power to the grid whenever demanded.  That would require storing much more energy per turbine and delivering it at rates sufficient to replace the entire output of the installation for at least several hours, along the lines of concentrated solar power installations with thermal storage.

Even these techniques don't get us to the point at which a dedicated wind farm or solar installation could replace a baseload coal-fired power plant of similar capacity running 80% of the time.  For starters, energy storage doesn't alter the total amount of energy collected from the wind or sun.  In an area with good onshore wind resources, generating the same energy as 100 MW of coal capacity would take around 267 MW of wind turbines, because the wind doesn't blow at optimum speed all the time, and other times it doesn't blow at all. The wind farm would also need enough storage to absorb any output over 100 MW, and then make up any shortfalls below 100 MW for the longest duration that would be expected.  The figures for a solar installation would be similar. It just doesn't sound very practical, unless storage became dirt cheap.

Fortunately for renewable energy developers, that isn't what grid operators expect of wind or solar.  In most situations the local grid takes their output whenever it's available, though not necessarily at the price that a generator capable of committing its capacity in advance or responding on demand would receive.  So there's a financial incentive for renewables to add a bit of storage to "firm up" some capacity, while bulk storage appears to be more desirable as a separate asset available to the grid, just like a "peaking" gas turbine, to support multiple renewable sources. Of course in that case there's no guarantee that the power stored would come from renewables.  It's likelier to come from whatever is the cheapest off-peak generation in that market.

So while it's easy to see how improved energy storage can enhance the economics of renewable energy and enable it to be integrated into the grid to a greater extent than otherwise, it's less obvious that even cheap, large-scale energy storage is a panacea for intermittent renewables like wind and solar.  It might even have greater benefits for low-emission but more reliable forms of generation, such as nuclear and geothermal, by allowing them routinely to shift a set portion of their output into more valuable segments of the regional power market. 

Disclosure: My portfolio includes investment in GE, which makes products mentioned above.

The Forgotten Renewable

An editorial in the New York Times last week highlighted a topic I've been meaning to comment on for some time, the gradual demise of our oldest and still largest source of renewable energy: hydroelectric dams. Along with lauding plans to remove several West Coast dams in order to protect fish populations, the Times urged the dismantling of the four large power dams on the lower Snake River in Washington state. The disconnect between that position and the paper's long-standing advocacy of stronger measures to address climate change is remarkable, considering the elimination of 3,000 MW of zero-emission power generation that would accompany the loss of these dams. But if the unpopularity of existing hydropower dams in environmental circles explains the exclusion of this vital energy resource from the definition of "qualified renewables" included in the proposed national Renewable Electricity Standard (RES) of the Waxman-Markey climate bill, that hardly excuses a policy so counter-productive for our efforts to reduce greenhouse gas emissions.

Consider the four dams in question. I can't speak to concerns about declining salmon populations or other habitat issues, though I note that the dams in question are all "run of river" facilities, without large reservoirs. What is clear, however, is that if the four facilities typically operate at the national average hydropower utilization rate of around 36%, their annual power generation would come to about 10 million megawatt-hours (MWh) of electricity, equivalent to the output of 4,000 MW of wind capacity, or roughly 20% of the entire US wind power output in 2008. After a banner year for wind turbine installations in 2008, the US might not add much more new wind capacity than that this year, and wind remains the largest-scale technology among our preferred renewable power options. In fact, since 1999 US hydropower output has declined by an amount greater than the entire current contribution of wind power. That means the emissions benefits of a decade of dramatic growth in wind and solar power have been negated by the loss of hydroelectric generation--a loss that the authors of Waxman-Markey have chosen to ignore by counting in their RES only "incremental hydropower", which they define as

"(A) energy produced from increased efficiency achieved, or additions of capacity made, on or after January 1, 1988, at a hydroelectric facility that was placed in service before that date and does not include additional energy generated as a result of operational changes not directly associated with efficiency improvements or capacity additions; or
`(B) energy produced from generating capacity added to a dam on or after January 1, 1988, provided that the Commission certifies that--
(i) the dam was placed in service before the date of the enactment of this section and was operated for flood control, navigation, or water supply purposes and was not producing hydroelectric power prior to the addition of such capacity;
`(ii) the hydroelectric project installed on the dam is licensed (or is exempt from licensing) by the Commission and is in compliance with the terms and conditions of the license or exemption, and with other applicable legal requirements for the protection of environmental quality, including applicable fish passage requirements; and
`(iii) the hydroelectric project installed on the dam is operated so that the water surface elevation at any given location and time that would have occurred in the absence of the hydroelectric project is maintained, subject to any license or exemption requirements that require changes in water surface elevation for the purpose of improving the environmental quality of the affected waterway."

In other words, a utility would be able to count increases in hydropower towards its RES compliance only if they came from certain carefully-specified improvements, while the sole penalty for lost hydropower capacity and output would be an increase in the base amount on which the RES would be calculated. So at the full 20% RES level for 2020 and beyond, a MW of new wind, solar or other "qualified renewable" capacity would count 5 times as much as a MW of hydro dismantled.

This mismatch speaks to our conflicted attitudes toward climate change and the broader issues of sustainability. I'm sure that those advocating the removal of these dams would argue that we shouldn't make such decisions on the basis of any single criterion, even one as important as greenhouse gas emissions. Yet that view is at odds with the underlying philosophy of a climate bill that aims to do more than just level the playing field by imposing a charge on greenhouse gas emissions to account for the environmental externality not captured in the economics of the energy market. In addition to its skewed version of cap & trade, Waxman-Markey would stack the deck for a chosen group of renewable energy technologies, in the process excluding the one that produces more zero-emission MWhs than all the rest put together. When the Senate takes up this legislation, it should abandon this narrow focus on specific technologies in favor of one that creates a positive bias for all our low-emission sources, including hydropower and nuclear energy. For a government so determined to demonstrate our seriousness about tackling our emissions, in advance of December's Copenhagen climate conference, that would speak far more loudly than another thousand-plus pages of convoluted new regulations.

The Wrong Enemy

While reading an article on oil company taxation in the Wall Street Journal, I ran across a quote from Treasury Secretary Geithner that crystallized my growing impression that the administration has misinterpreted its own mantra on energy and is training its "friend or foe" radar on the wrong enemy. I would paraphrase the Obama energy strategy as seeking to reduce US oil imports and greenhouse gas emissions by strongly promoting renewable energy and energy efficiency. Unfortunately, the administration's actions risk putting the domestic oil and gas industry on the wrong side of the divide that creates. Absent the steady output from our oil & gas producers, improved energy security--let alone energy independence--would become simply unattainable no matter how many wind turbines and solar panels we build in the next few years. Domestic oil & gas is not the enemy; it is a natural ally in the administration's quest to wean the US from our harmful over-reliance on foreign oil.

Policy makers must have a clear understanding of the country's energy balance and the relative contributions of our different sources. I looked at these "Big Chunks" in some detail in January. Domestic oil and gas production covers 34% of the nation's energy needs. Imported oil provides another 28%, and that's the chunk we need to focus on, along with the emissions from coal-fired power plants. When Secretary Geithner said, "We don't believe it makes sense to significantly subsidize the production and use of sources of energy that are dramatically going to add to our climate change," he was implicitly lumping oil and gas from all sources together with coal. Although he was correct to the extent that domestic oil and gas--just like the imported varieties--emit CO2 and other greenhouse gases, there is simply no way to keep the US economy running in the near-to-medium term without them, emissions or not.

Consider the latest figures from the Energy Information Agency of the Department of Energy. In 2008 "other renewables", excluding hydropower, generated 3% of the US electricity supply. Wind, solar and geothermal power--the non-hydro renewables that the President has targeted for doubling in the next three years--contributed just over half of that, or 1.6% of the total. That's up from 1.2% last year, for an impressive growth rate of 36%. If the renewable energy sector can maintain that growth for three years, helped by the stimulus package, it should easily double to 3.2% of our electricity supply. That might push the broader "other renewables" category close to 5%, and total renewables including hydropower to 10 or 11%--but all without displacing more than a tiny amount of oil, because oil (including petroleum coke) accounted for just 1.1% of net electricity generation last year, and plug-in vehicles aren't yet a measurable fraction of our vehicle fleet. Oil-burning power plants consumed 165,000 bbl/day, a paltry 0.8% of US petroleum demand. Even if the output of every new wind turbine and solar panel were devoted to backing out oil-fired power--a practical impossibility, given the geographical and time-of-use patterns involved--it wouldn't make a dent in our oil imports.

Increasing the tax burden on the oil and gas industry, by contrast, would most assuredly make a dent in our oil imports--by expanding them. Despite a recent uptick in oil prices, oil companies have seen their cash flows decline significantly in the last nine months. Under pressure to support dividends, those that can still borrow to maintain their capital investment programs are doing so; others have had to defer projects or sell off assets. Increasing their tax burden by revoking long-standing oil & gas tax breaks and singling the industry out for exclusion from a tax benefit offered to all US manufacturers, even with the logic of leveling the playing field for energy sources that emit greenhouse gases relative to those that don't, would be ill-timed, at best.

When the industry argued against higher taxes last year, some suggested that we were entitled to raise taxes on oil companies because political risk was lower in the US than elsewhere, while companies were denied access to key resources overseas. Those comparisons have shifted noticeably, as producing countries have become more receptive to foreign investment in their oil industries, thanks to the rigors of lower oil revenues. At the same time, political risk here has increased, as described in a provocative op-ed by Ian Bremmer of the Eurasia Group. The energy industry has already seen signs of this, in a proposal for an excise tax targeting companies that refuse to renegotiate the royalty relief provisions of certain Gulf of Mexico deepwater lease contracts, which were recently upheld in court. No business leader can watch the current spectacle of "outrage" and fail to wonder when he or she will sit in the hot seat.

This isn't a question of seeking sympathy for companies that have just come off a streak of record-setting profits, most of which were plowed back into the business or returned to shareholders. That would be as fruitless as soliciting aid for AIG's financial products employees. Rather, we need to look to our self-interest, here. When an oil company drills in the US, its production backs out imports directly, barrel for barrel. It pays US salaries--attractive ones--and it pays hefty taxes: income taxes at a 40% effective rate, along with billions of dollars in royalties, rents and bonus bids collected by the government. When a US oil company drills elsewhere, much of the benefit is captured by foreign governments, and when the oil we import comes from a non-US supplier, our trade deficit swells and the federal government only gets to tax the profits on refining & marketing, which are often pretty thin.

In the future, when we've cracked the code for producing liquid fuels cheaply from abundant non-food biomass, covered our hills and shorelines with wind farms and our deserts and roofs with solar arrays, and have sufficient domestic energy supplies--used efficiently--to back out the last of our oil imports, then the time will be ripe to talk about winding down the domestic oil industry, along with the emissions from the remaining petroleum products. Until then, rather than penalizing them on the basis of fractured logic suggesting this will somehow reduce our oil consumption, it is very much in the public interest for the government to treat the domestic oil industry as a partner, not a foe, and refrain from making it less attractive to drill in the US.

Catching the Flow

Of all the different technologies for producing energy, I've probably devoted the least space in this blog to those that extract energy from flowing water. Large hydroelectric dams are hardly novel; they generate about 7% of our electricity. But at least in the US, most of the attractive locations for large-scale hydropower have already been dammed or determined to be too pristine to exploit. "Mini-hydro", in the form of small dams or "run of river" installations is an interesting alternative, and it looks a lot more palatable than its larger cousin. The other day I ran across a link to a video report on a project that has fascinated me since I first heard about it in the late 1990s. It is a hybrid of hydropower and tidal power, tapping the tidal energy of the East River alongside Manhattan with turbines installed on the riverbed.

The initial size of this project is tiny; it will only power a supermarket and parking garage, when it runs, but the developers hope to scale up to 10 MW--still a lot smaller than the typical power plant or wind farm. This kind of tidal power application falls somewhere in the middle of the spectrum of renewable electricity sources: much more predictable than wind, but less reliable than geothermal or conventional hydro. Where it shines is in its unobtrusiveness, which might enable it to fly under the NIMBY radar in a way that wind turbines can't.

For that matter, the turbines used in the East River ought to work just as well in a river flowing due to gravity, like the St. Laurence, instead of one that reverses flow when the tide changes direction. It could provide a useful alternative to the standard approach to mini-hydro, which avoids large dams and reservoirs, but still entails diverting and empounding a portion of the flowing river. The reliability and environmental impact of "kinetic hydropower" remains to be determined, however. I will be watching the East River project with interest to see whether this emerges as a viable competitor or ends up as another interesting, but not very practical energy idea.