And with this two-part scheme, games are played. Wind generators can bid a low price into the pool only to receive a higher FIT, which gives them an incentive to underbid. This might reduce the pool price but not overall cost to Germans for electricity.

Investing in New Generation: What Makes Sense?

If a generation resource is a good investment for its developers then it must return a profit to them.  In a normal electricity market this profit comes from supplying a segment of the demand (peak, intermediate/cycling, baseload) from a plant that is efficient technically and financially.

For existing plants and determinations of electricity costs in the here and now we can figure out the average cost of supplying electricity by calculating the weighted average cost of supply for each time period in the market every day.  If the addition of one generation source raises this weighted average without improving service quality or reliability, then it is not economical and would generally not be chosen in a well-functioning market.

But what about the future?  Electricity suppliers must invest large sums in new generation plants with the expectation that these plants will meet demand at the least cost.  This cannot be known with certainty, and mistakes are made all the time, especially when government policy and rent-seeking drive investment choices.

Transmission network operators – those in charge of the “natural monopoly” part of the power business – try to reduce the risk attendant to future supply by figuring out the least costly way to supply power and energy to their customers in the future, including the wires to transmit the electricity.  They have to take account of a long list of considerations: investment cost, fuel supply, emissions and licensing regulation, proximity to existing load centers and transmission nodes, transmission congestion – you get the idea.

The transmission system operator also has to pay attention to public policy – renewable energy mandates (“portfolio standards”), federal tax incentives (producer tax credits for wind and solar), feed-in tariffs, powerful politicians who do not want their vistas impaired – in a host of ways that directly impact their views of an optimal future generating system.

What Does the Wise Transmission Operator Do?

A wise investor in generation will first figure out what is economic to build? what are the physical constraints on the system? and finally, what limitations will public policy put on otherwise least cost generation choices?

A Case Study of “Germania”[i]

Let us imagine that we have a rather large and wealthy country to play with, one that currently has about 129 GW of installed generation capacity.  Further, we can imagine that this wealthy country, responding to its powerful environmental movement, has decided to

(i) phase out nuclear power;

(ii) limit future coal power-plant operations;

(iii) build a lot (a lot!) of wind generation plants; and

(iv) bring in most of its gas supply from Russia at prices linked directly to refined oil products and crude (i.e., high and volatile).

Such a country would have a great deal of baseload generation capacity – coal + lignite + nuclear – perhaps half of total generation capacity (US has coal + nuclear capacity of about 40%).  Suppose further that green thinking had created incentives (FIT) that pushed wind up to about 20% of total nameplate capacity.  Most of the country’s hydro generation and imports are soaked up by wind mirroring and shadowing.

With all of that generation capacity essentially independent of fuel price trends it is no accident that the cost of generating electricity in Germania is (i) high; and (ii) not responsive to changes in oil and gas prices.  At current world oil prices the average cost of electricity generation in Germania is about 6.7¢/kWh (7.8¢/kWh if crude reaches $110/bbl).

Germania’s Least-Cost Generation System

With natural gas still expensive – kind of like burning oil but more efficiently – what does a least cost generating system for Germania look like in 2020, about the time the initial wave of early “teens” investments go on line?

The first thing you do is throw out the phase outs – keep the existing nuclear and efficient coal plants in operation until you have a more cost-effective substitute;

Second, phase out your highest cost oil plants – heavy fuel oil and old combustion turbines (2.6 GW)

Third, build some new, more efficient coal plants (1.6 GW) and CCGT units (4.5 GW), and nuclear (4 GW), reduce emissions per kWh by more than 30% in the new coal plants;

Fourth, operate existing wind (28 GW) but do not build new generation from that source.

Total annual cost in 2020: $48 billion at 6.7¢/kWh for average supply cost and 6.6¢/kWh for new supply.

Back to Our Previously Scheduled Programming

Everyone in Germany’s power sector knows that this least cost system is simply some renegade economist’s fantasy.  Back in the Real World of Energy Policy, there are several important considerations that must be accommodated:

Stay clean – phase out at least 25% of older coal and lignite plants, make permitting of new coal plants difficult;

Stay green – stay the course on wind energy; and

No nukes – continue to phase out nuclear power.  Build only enough new nukes to keep the Gauls happy.

So what does Germania get for its $53 billion annual outlay for electricity (at 7.6¢/kWh average supply cost and 7.8¢/kWh for new supply)?

Less coal and lignite – existing units fall to 45 GW from 58 GW, new coal rises to 3.1 GW to make up for some of the lost legacy capacity;

Less nuclear power – existing nuclear capacity falls to 15 GW (from 19 GW), new nuclear capacity falls to 2.7 GW from 4 GW in the least cost case;

More gas – 6.5 GW of new CCGT, up from 4.5 GW in least cost case;

More wind – another 17.5 GW, for a total of 35.5 GW of wind, 25% of total nameplate capacity; and

More imports – enlarged interconnection with Benelux and Denmark/Norway is only cost effective way to shadow additional wind and meet peak demand.

And if the price of oil rises to $110/bbl by 2020, then this system will cost Germania $62 billion annually at 8.8¢/kWh.

The True Green Scenario – phase out 50% of coal and nukes, double wind installations, increase imports – costs about 7.9¢/kWh on average, 8.3¢/kWh for new supplies and carries annual costs of $56 billion.  This option requires 15.6 GW of new CCGT, 2.1 GW of new combustion units, 10.6 GW of import capacity and operates existing HFO units at 100% of capacity (!), even building a couple of new HFO plants to meet demand – not green, not cheap and not feasible (it only solves inside the box).  And by the way, higher oil prices for this beauty will cost $66 billion/y at 9.3¢/kWh.

Does ‘Green’ Always Have to Hurt?

Easing off the green pedal a bit creates enough breathing room in Germania to generate a lot of clean electricity at a much lower cost.  A more moderate program, even with 10 GW of new wind, can be done at a far lower cost with just a few adjustments:

Slow the phase out of existing coal and nuclear plants – keep 85% of existing coal and nuclear plants in operation in 2020;

Build new coal and nuclear plants – reduce emissions per kWh and burn less coal overall, and improve the efficiency and security of the nuclear fuel cycle;

Import more – let more medium term supply come from lower cost Benelux and Scandinavian suppliers to mirror/shadow wind and follow load.

A more moderate program of this sort could supply Germania for about $49 billion annually at an average cost of 6.9¢/kWh.  Even higher oil prices do not hurt as much as in the more aggressive scenario, with $110/bbl crude oil increasing total annual costs to $56 billion at 8.0¢/kWh.[ii]

As a Great Philosopher Once Said, “A man’s got to know his limitations”

In a world of unlimited wealth, where electricity can be stored and plants can be built instantaneously on a whim, a complete remake of a large power system seems feasible and even desirable to some.  Back in the real world, where everything takes time, costs money and different sources of electric power are not perfect substitutes for one another, such ambitions are difficult to realize.

Germania set up too many targets on too short a time frame.  The result was a series of conflicting mandates and constraints – close it down; no, we need it, keep it open; will the Jutes cooperate on supply? What happens to our gas supply when “bad weather” rolls in from the East (as it eventually does in Germania)?

A cleaner, greener power supply system is possible over a longer period of time at a far lower cost than a crash program.  Orderly replacement of older coal plants with more efficient and cleaner new ones makes sense given the country’s resources, geography and demand patterns.  As in the US a crash program to overhaul the system will ultimately force increased reliance on older, less efficient coal plants; it ignores microeconomic rationality for chimerical goals and wastes a lot of money and energy in the process.  Or to paraphrase that revered Soviet philosopher, “you may not be interested in markets, but markets are interested in you.”  Germania ignores market forces at its own peril.

[ii] The cost of new supply is below the average cost of supply by about 7% for this moderate scenario, while the “Green” future shows new supply above average cost by about 2-3%.

At the same time shale gas has been more than a headache for LNG exporters and pipeline monopolists, for some it threatens to become a nightmare – softening prices, competing with pipeline supplies, driving LNG demand to spot markets – generally making a pain of itself, from the viewpoint of the gas industry’s would-be GOPEC.

By providing a plentiful alternative source of supply for the world’s largest gas market, the U.S., shale gas has reduced wellhead netbacks throughout the Atlantic Basin.  International reverberations have been dramatic. Even the Russian Bear, feeling the hot breath of the market, is softening its pricing terms for international gas sales.

“A Republic, if You Can Keep It”

At the close of the U.S. Constitutional Convention in 1787 a woman asked Benjamin Franklin, as he was leaving what we know as Constitutional Hall: “Well, Doctor, what have we got—a Republic or a Monarchy?”  Franklin replied:   “A Republic, if you can keep it.”  For natural gas, we can paraphrase Mr. Franklin – a market, if you can live with it.

In the U.S. and throughout the world the bounty of shale gas has created significant opportunities for consumers to save money on energy, and clean energy at that.  Most of these benefits are available only to countries where the market determines gas prices.

Consumers of gas in the U.S., where prices are set by a market, pay about half what consumers in Spain, Belgium and elsewhere pay for that same gas, with prices set by regulators and politicians.  Similarly, consumers of natural gas in the UK pay about half as much for gas from Algeria as do consumers in Spain.[i]

But it is not always this way.  Sometimes Mr. Market delivers a less friendly message -  Produce more!  Consume less!  Build a bigger house! – and punctuates the message with unpleasant price signals – spikes and crashes.  Twice during the 2000s, in 2005 and again in 2008, natural gas prices at the Henry Hub rose above $13/mmbtu, but only for a while.  Conversely, prices have cratered several times in the past decade or so – falling below $3.50/mmbtu four times since 1998.  The thing about Mr. Market is that he makes his point with real zing.  Prices did not stay at such levels for more than a few weeks.  Like the cry of the 101^st Airborne, Mr. Market delivers a focused message, one intended to motivate action, not talk.

In contrast, regulated prices[ii] provide the illusion of fairness – fair to the producer, fair to the consumer – all the while gouging the consumer and lulling the producer into laziness and greed.  Netback prices at the wellhead in Algeria or Nigeria, the GMT equivalent of the Henry Hub, have remained north of $7.50/mmbtu for years.  In contrast, the average gas prices in the US have remained well below that level for all but two years of the past ten.  Consumers in most European countries pay more than $15/mmbtu for the commodity gas by the time it is delivered to their houses.[iii]

No Free Lunch

Most of the time markets will deliver the goods in a reasonable manner and at a price that closely tracks the cost of providing the gas.  But this means that we, as consumers, have to listen to the news that the market delivers.  Usually we do, except for those times that we run to the leviathan for some help.

America is now in a unique position to benefit from a geological oddity – the shale gas deposits.  Moreover, consumers throughout the world can also so benefit.  But in order for all of this to work countries around the world will need to connect prices consumers pay with the prices that producers receive for investment, development and production.

And just when the energy world needs a market champion we have panic in the US Executive Branch.  The ill thought-out drilling moratorium in the US Gulf sets an uncomfortable precedent for opponents of shale gas drilling.  So far it is only the deep recession that has kept oil prices under control in the face of a poorly-thought-through policy on drilling.

With shale gas there would be no such luxury.  If fields are not subject to continuous drilling operations production may fall off rather rapidly.  So the response to a shale gas accident, no doubt the object of many Sunday prayers in the US renewable energy community, could cripple that supply, now more than 10% of US gas supply, and lead in short order to far higher natural gas prices.[iv] For Mexico, now a major LNG importer, the increase in prices due to a failure of the US shale program and its umbrella effect on gas prices throughout this hemisphere, could amount to more than 1% of that country’s GDP, an astonishing and unwelcome total given the current state of Mexico’s economy and society.  In particular, such a cost increase could cripple industrial production and raise the cost of power generation by 25% or more.

Even without an accident, shale gas opponents have already had some success in limiting production activities.  America’s gift could be withdrawn, and with it prosperity and comfort for millions all over the world.

[ii] This is the EU version of utility price regulation – prices to consumers are too high and incentives for producers for efficiency are low.  This model contrasts with the developing country regulatory model, where prices for consumers and producers are too low, leading to chronic excess demand and insufficient incentives for new supply.

[iii] This is rather confusingly displayed as the cost of gas per kWh – i.e., gas converted to electricity at 3412 btu/kWh (3600 MJ/kWh).  Prices range from about $10/mmbtu in the Baltics, to more than $25/mmbtu in Sweden and Denmark.  By way of contrast 2010 retail gas prices in the Mid-Atlantic region of the US are about $8/mmbtu for the commodity (including storage) and $3.25/mmbtu for distribution.  The remainder of charges, now totaling about 10% of the consumer’s bill, consist of taxes and renewable energy levies.

[iv] The end of the shale gas effect on US and international gas markets would mean increased prices of at least $75 billion annually in the US, $60 million annually in the Dominican Republic, $11-12 billion/year in the UK and $10-11 billion/year for Mexico.

Their soundbites start with a half-truth and end with a fallacy.  We are told that “60 percent of U.S. energy supplies still come from oil and gas,” with the implication that (i) all of that is imported; and (ii) the pittance that we produce domestically all comes from offshore facilities.

 It is true that 60 percent (actually 62.5%) of our energy comes from oil and gas.  But the portion that comes from natural gas, about 24% of total U.S. energy supply, is 85 percent domestically sourced.  With oil and liquids, about 45% is domestically sourced.  Sure, we use a lot of oil and gas, and most of it, more than 60%, comes from the U.S.  More than two-thirds of that domestic production comes from onshore production facilities.

The fallacious recommendation that emanates from the incomplete data is that the U.S. has no chance to remain a viable society and economy if we continue to rely on all this foreign (onshore, Alaska, ethanol, Saudi Arabia, Russia, what’s the difference?) and offshore supply.  ”Therefore, we have no alternative but to turn to  .   .   .   wind, solar, biomass?”  The agenda pushers never want to let a good crisis go to waste.  But very quietly, mostly out of sight of the energy policy crowd in Washington, we have seen the emergence of major new sources of domestic energy production – natural gas from coalbeds and shale formations.  So great has been the rise in domestic gas production that it has weakened gas prices worldwide, benefitting users in homes and industry.

Moreover, the US example is setting off emulation in Australia, Canada and China, as well as Europe, promising still further major gas production increases.  Without this production the major conventional gas powers – Russia, Qatar, Algeria, Iran, Libya, Nigeria – would be able to garner ever-increasing market share, and with that monopoly rents and political power.

It was just such a calculus that Russia employed in its approach to foreign gas customers in Europe, China and the former USSR.  Ignorance of market forces and developments has severely weakened Russia’s market and political power to use the “gas weapon” (sounds like a Mel Brooks movie) on Europe, China, Japan and the US (though Russia has “taken” Ukraine as a consolation prize. see below).  Following uninformed policy hacks could return the US to those days, but only if we let them lead us there.

In addition to the monetary and political costs of listening to the interventionist voices of doom there are also serious environmental implications.  Producing oil and gas offshore is generally far more benign environmentally than increased shipments of oil in tankers.  And the same people who decry offshore oil platforms would be first in line to oppose siting of LNG regasification plants, the real alternative to domestic gas production.  On the electric power side, the two major contenders, if we “get off gas,” remain coal and nuclear.  But coal is not likely to be nearly as good a citizen as gas for power generation for many years – not until we can mine it with robots and burn it as cleanly and efficiently as we do gas.  As for nuclear, it would take a great leap of faith to think that our political system can deal with this technology in an adult manner, and even then gas-fired electricity is less costly and will remain so for many years.  Politically, rising domestic US gas output promotes a market-oriented energy agenda – private companies investing in output on private land, selling to willing customers -the antithesis of the statist agenda imposed by most recent energy legislation.  If we help ourselves we establish a virtuous circle with financial, economic, fiscal, environmental and political benefits for the US and for the world.

Russia’s Gas Politics – Lessons Unlearned

When last we looked at natural gas politics in Russia and its near abroad, the Russians were planning to surround Ukraine with pipelines, facilitating all manner of selective gas supply strategies to Ukraine and Western Europe.  However, financial reality has caught up with Gazprom, the monopoly gas supplier; spending $40-60 billion to strangle recalcitrant Ukrainians and Poles has proved at bit much, even for Gazprom.  A combination of too much spending and too little productive investment, coming at a time when others were ramping up (shale) gas production and LNG has produced a perfect storm for the Russians: falling gas prices and more competition for EU market share.

Source: http://www.eia.doe.gov/emeu/cabs/Ukraine/images/NGPipestoEurope_Manuel.gif

Lower Natural Gas Prices are Good for the World

Natural gas is the go-to transition fuel for the world.  Clean, easy to use and widely available.  With US domestic gas production up more than 10% in just the last 3 years the world market has been transformed.  This stunning turnaround in US production has led to lower prices, reduced imports, especially LNG, and improved competitiveness for US industries using gas as a feedstock, including the vital petrochemicals industry.

With millions of tonnes of unused import regasification capacity the US has created gas-on-gas competition not only in the Western Hemisphere, but in Europe as well.[i]

So plentiful are shale gas resources in North America that LNG terminal plans are even going in reverse.  In Western Canada there are plans to use a proposed LNG import/regasification terminal to liquefy and export (to China) shale gas from the Horn River formation in British Columbia.

China, naturally, is anxious to obtain as much leverage on its other gas suppliers as possible.  If they can purchase gas that is not indexed directly to oil product prices then they have a tool to push down costs from other suppliers.

Mr. Market Rears His Head and Slaps Down the Gas Cartel

Behind the scenes the major gas-producing countries, hoping to vacuum up rents à la OPEC, have seen their cherished dream, charging higher prices to the world’s natural gas consumers, founder on those pesky gas producers in the US, Canada and Qatar.   While Russia, Iran and Algeria hope to drive gas prices higher, more in line with oil, by withholding supplies, others do not agree.

Qatar, one of the lowest cost producers in the world, and the largest exporter of LNG, has refused to cut output of natural gas.  As much as the Russians might like to play the same role for gas that Saudi Arabia plays for oil, it is not to be; there is simply too much gas bubbling up all over the world and consumers have the luxury of choice among suppliers.

With natural gas production in the US well above levels predicted just a few years ago, excess capacity has built up in the LNG side of the business.  This means that “unclaimed cargoes of LNG are now widely available for those who are able to purchase gas on the market.”  Such spot cargoes of LNG are going for knock-down prices.  Netbacks to producers in Trinidad for delivery to the US are just over $2/mmbtu, and less than $5/mmbtu delivered to the US Gulf Coast.  For those in Europe with functioning gas markets (the UK) LNG cargo prices are more than $4/mmbtu lower than prices in countries locked into oil-equivalent pricing formulas.  This means that the UK gas distribution system can purchase gas from Algeria or Nigeria for about $5.50/mmbtu, while contract customers in Spain pay about $9-10/mmbtu for cargoes from the same sources.

Even India, far from the center of shale gas production, has seen sizable benefits from the changing world gas market.  Recently, an LNG importer in Gujrat state was able to obtain LNG from Trinidad’s Atlantic LNG for $8/mmbtu, cif.  Russia’s gas customers still pay more than that for pipeline supplies.

Maybe Gazprom Does Not Really Understand Markets

Monopolists, especially those with natural resource based industries, often overestimate their market power and underestimate potential competitors.  Russia appears to have done so.  So confident were they of the power conferred by their gas resources, proximity to European markets, and control of pipelines that they missed the change in the correlation of forces in world gas markets.

Once the strict link between oil and gas prices is broken it is difficult to insist that the two products are the same, and that gas should be priced like a liquid, compact and easily transported commodity.  And yet, for many years, Gazprom was able to charge oil-equivalent prices for its gas exports to Europe.

By tying up the available transmission routes from Asia to Europe and by intimidating the transit or competitor countries, Russia believed that they could dictate terms to both Western Europe and Ukraine but also to China.

So focused were the Russians on controlling the transit of gas through Ukraine that they reprised the old line “I liked the company so much that I bought it.”  Only in this case they “bought” Ukraine.  To keep the Ukrainians sweet, and to get naval basing rights at Sevastapol they cut the price of gas to Ukraine from about $10/mmbtu to just under $6/mmbtu.

The Long Arm of the Law of One Price Reaches Out to Gazprom

Surely such discounts will not go unnoticed in Western Europe.  No one wants to pay more for a commodity than they must, and since the Europeans are already reducing their gas take from Russia the next step is to renegotiate the pricing basis of their supply contracts with Gazprom.  The discounts resulting from such renegotiations are likely to cost Russia at least $25 billion in lost revenues per year.

The bad news does not end there for Gazprom.  So focused was the company on its European customers, pipeline investments and new gas supplies that they ignored the major new customer in the East, China.

Fresh from negotiating discounted prices for LNG supplies, China asked Gazprom/Russia, Kazakhstan and Turkmenistan to offer similar discounts for pipeline supplies to Western China.  Its attention elsewhere, and apparently overestimating its market power, Gazprom refused to deal.  The result is the 1,833 km (1,137 mi.) pipeline that will carry 40 bcm (3.9 bcf/d) to China’s Western Region.  Another 10 bcm (~1 bcf/d) of annual production from Kazakhstan will tie into the same transmission project, effectively cutting out Russian suppliers for years.

Shale Gas: Good for the US and Good for the World

As noted at the beginning of this article North American shale gas production has started a massive restructuring of prices and trading patterns throughout the world.  So far the victims include mighty Gazprom, its Russian masters, and, as collateral damage, political freedom in Ukraine.  Others, including Libya, Iran and Algeria, along with Hugo Chavez’s Venezuela and Hugo Morales’s Bolivia will not see their gas cartel wishes or its monopoly rents come to pass anytime soon.

On the winner side are North American gas consumers, domestic gas producers in the US, Australia and Canada and large consumers worldwide who are not lashed to the Gazprom mast.  These include China, Britain, and possibly others in Europe, if they open their gas markets to new suppliers.  The incentives to open up gas markets may now greatly exceed the cost of Gazprom’s wrath.

The threats to this happy state of affairs arise primarily from the US political system. Gas from shale and other unconventional sources will play a critical role in bridging US electricity supplies as coal and nuclear expansions look increasingly problematic.  Gas is likely to be the fuel of choice to supply the electricity as a substitute fuel cycle for the more than 45 proposed coal-fired power plants awaiting (and awaiting) regulatory approvals. Without shale gas, and if coal remains in the penalty box as a future fuel for power generation, US imports of LNG would need to roughly quintuple.  Such a reversal would send gas prices back up to 2008 levels rather quickly and would create their own political problems on siting and transmission.[ii] It is difficult to overstate the siting difficulties that such an expansion of regasification terminals might generate.

We have in our power the ability to create and sustain an efficient, dynamic and responsive market-based natural gas system for much of the world.  On the other hand, we can be small-minded and deliver ourselves into the arms of “GOPEC.”

[ii] For example, if the 45 coal plants were to be replaced by natural gas combined cycle units, as the opponents of coal would prefer, and if shale gas were to succumb to its own environmental foes, then the US would need to import an additional 80 million tonnes of LNG annually to supply those gas-fired power plants.  In contrast, current US imports of LNG are about 11 million tonnes, and the peak in 2006 was just below 18 million tonnes.

Part I demonstrated that the served-household claims is fanciful. In reality, no more than 49,000 households could be “supplied”, and these with only a minimal degree of assurance. Indeed, the wind project is more costly than a diesel backup scheme that would actually be capable of supplying reliable power to several hundred thousand households. The wind project is also three times more costly than a replacement of just 211 MW of older coal capacity with new technology that would provide a similar reduction in emissions, while supplying firm power to the NW Power Pool’s customers.

Opportunity-cost economics, anyone?

The key to wind’s providing some degree of fuel and emissions savings is its ability to deliver reliable electricity without shadowing or backup by hydrocarbon-using plants. These shadowing/backup requirements in the Northwest (NW) Power Pool may be able to take advantage of existing surplus hydro capacity in that region during off-peak periods (spring and fall), thereby permitting the proposed plant to reduce hydrocarbon consumption and emissions somewhat during those periods. It is not reasonable to expect to achieve the claimed emissions savings, but lower figures, less than half the publicized savings, may be possible.

In particular, the addition of wind generation, with shadowing/ backup provided by reservoir hydro, may be able to reduce overall CO2 emissions in California, the ultimate customer for the electricity produced by the GE project during Oregon’s two surplus seasons. But during the winter and summer peak demand periods, less hydro output is available, peak demand is greater and the shadowing backup will be provided by some combination of gas-fired and coal plants. What it is critical to keep in mind is that maintaining stability in the NW Power Pool requires the pool to shadow/backup not only the proposed new project, but the other 6.4 GW of existing wind as well.

Going further, our analysis shows there are less costly and more effective alternatives readily available that rival or exceed the claimed benefits of this wind project.

Wind Shadowing/Backup Requirements

So what is needed to ensure that wind plants deliver reliable electricity? They have to be paired with conventional, reliable generators capable of mirroring wind’s volatile and unreliable output. This can be called wind shadowing/backup capacity. It is shadowing wind when wind is producing, albeit it in a volatile manner. It is backup to wind, in the more usual sense of the word, when wind is producing nothing, which can be for extended periods.

When claims are made about wind displacing fossil fuel plant production, the question that should be asked first is: what is providing wind shadowing/backup? With system reliability and power quality considerations coming to the fore, it becomes evident that the shadowing/backup is what is displacing the fossil fuel production, and wind is displacing some small measure of the shadowing/backup. An earlier article explored the realities of this and showed that a wind project that relies on fossil generators to shadow the wind machines may provide little net fuel or CO2 displacement and in some cases may actually increase fuel use and emissions. The latter result may obtain as a result of: (1) the imposed inefficient operation of the wind shadowing/backup, as well as (2) use of shadowing/backup technologies that are less efficient than the pool’s major generation resources – coal, nuclear, gas-fired combined cycle. The three generation sources listed above are in varying ways not generally suitable for providing shadowing for wind. In each case the ramp rate of the generator is too slow in reacting to many of the transients of wind production. Consequently, shadowing and backup must be provided by smaller, faster acting, but less efficient engines. If the shadowing/backup requirements are significant – that is, if wind output is large relative to overall system capacity, even approaching 5% – then the reliance on small, inefficient engines or combustion turbines (GTs) will arguably lead to a net increase in fuel use and therefore emissions.

The general considerations are:

• Wind shadowing/backup must be able to respond to wind’s volatile nature, and candidates, with varying degrees of ability to do this, include gas turbine, coal, hydro and small diesels.
• What generation capacity mix will be displaced by the combination of wind and shadowing/backup.
• As the junior member in the mix, wind replaces the shadowing/backup for purposes of CO₂ emissions calculations.

Normally, the full and accurate computation of the technologies involved in shadowing/backup of wind will require a system dispatch model so that minute-by-minute variations in wind output can be shadowed by fast ramping engines or valves (hydro). Table 1 summarizes some of the possible scenarios.

Table 1 – Some Wind Shadowing/Backup Scenarios In the NW Power Pool

In scenarios A, B and C, the inefficiencies imposed by wind volatility on the shadowing/backup plants can more than offset the CO2 emissions “saved” at the point of wind generation. In any event, Scenario C is relevant in the NW Power Pool only insofar as coal is used as a resource in the pool, and coal-fired electricity enters this pool largely through imports. In case D, assuming no curtailment of wind during high wind production periods and no spillage of hydro is required because of the timing of wind production relative to reservoir levels, the wind production could be replacing that of fossil fuel, as indicated by “Other”. In case E, wind is replacing hydro and no CO2 emissions are saved (generally wind acts similarly to run of river hydro, in terms of system stability, with the exception of such cases as hydro plants at Niagara). Note that the conditions for case D are seldom met during annual peak demand periods in the NW Power Pool, as noted in Part 1.

The Oregon wind plant production is slated to go to Southern California Edison, which obtains over 50 per cent of its electricity from imports (out of state) and almost 40 per cent from thermal generation within its jurisdiction. As California as a whole gets 50 per cent of its in-state generation from natural gas and about 2 per cent from coal/oil, it is reasonably assumed that the wind/shadowing-backup combination is displacing gas, mostly in combined cycle plants. It is possible that some imported electricity is being displaced, which likely contains a higher proportion of coal.

The question remains: what is being used as wind shadowing/backup? Oregon has the following electricity production profile – hydro 61 percent, gas 27 percent, coal/oil 8 percent, and other renewables 4 percent. A reasonable assumption is that impounded hydro is being used within Oregon for this purpose during shoulder seasons (spring and fall), while gas and possibly coal are used during peak seasons (Summer and Winter). In off-peak seasons in Oregon and the NW Power Pool, case D generally applies and Oregon is basically exporting hydro and some wind. Case A or B applies during peak seasons, and gas or coal is likely exported.

CO2 Emissions Saved From Wind Generation

The foregoing illustrates the complexity of determining the impact of wind plants on fossil fuel and CO2 emissions reductions in electricity systems. The following completes the application of this to the new Oregon wind plant.

The wind project sponsors claim that 1.5 million tons of CO2 emissions per year will be saved as a result of this investment. Accepting the premise that no shadowing/backup will be needed the most likely result is for the wind to displace gas-fired CCGTs, at 0.4 tons CO2 emissions per MWh:

845 x 0.30 x 24 x 365 x 0.40 = 890,000 tonnes or about 0.9 million tonnes per year

For a 25 per cent capacity factor, more reasonable for onshore facilities, the CO2 emissions saved become about 0.7 million tonnes per year. The actual savings are likely to be far less than this calculated figure, since hydro capability is reduced during the winter peak demand period, one that coincides with troughs in wind availability as well. As a result, and as indicated above, the NW Power Pool is likely to be exporting gas/coal generated electricity to Southern California during the winter demand peak as well as during the summer peak. In fact, any coal-generated electricity exported to cover the supply obligation of the wind farm is likely to come from the same plants in Utah, Montana, Arizona and Nevada that currently provide the overall grid stability for Southern California Edison and California in general – a contractual round trip that contributes little or nothing to net energy supplies and saves little or no fuel/emissions.

It should be noted that potential savings of fuel/emissions during shoulder periods (fall and spring) comprise a special case because of the large hydro capability in Oregon during such periods. In the more general case and during the summer and winter peak demand periods, with gas or coal used for wind shadowing/backup, the CO2 emissions savings would reverse and net fuel use/emissions would rise due to the inefficiencies imposed on these plants. In fact with wind, currently at 6.4 GW, expected to approach 10% of pool generation capability in the NW Power Pool with the new project, the ability of the smaller, faster responding and more efficient shadowing engines described in Power Magazine are likely to be impracticable, since more than 800 of such engines would be required, meaning that shadowing/backup will be supplied by gas turbines, with the attendant inefficiencies and high fuel consumption, especially during startup. During lulls in wind a system of this size will require significant conventional generation resources for shadowing/backup.

At this point, a reasonable expectation is that half of the reduced CO2 emissions shown above would be achieved, given that the generation savings are valid for roughly half the year, spring and fall seasons; that is:

50% of 0.7 = 0.35 million tonnes per year

Since providing shadowing/backup for the NW Power Pool’s overall wind generation capacity of 7.3 GW, including the proposed GE project, involves large combustion turbines, then the fuel used just for startup, about 8-10 tonnes for each turbine each time, needs to be debited from the emissions reductions account to the wind plant. Each startup cycle, using liquid fuel or pressurized gas, produces about 100 tonnes of CO2 . To back up the NW Power Pool’s wind capacity would put roughly an additional 90 million tonnes of CO2 into the air, that is:

75 units x 12 start ups for each x 100 tonnes CO2/startup = 0.090 million tonnes per year

The GE project’s share of the shadowing/backup startup CO2 emissions (~11%) would be roughly 9,900 tonnes, offsetting about 3% of entire calculated CO2 savings for the 845 MW project.

Emissions savings identical to those claimed for the new wind project can be accomplished at significantly lower cost simply by replacing older coal-fired power plants (<35% conversion efficiency and relatively dirty) with current “ordinary” coal fired plants (~41% efficient and much cleaner). “Ordinary” current technology would reduce emissions in the pool by 0.22 million tonnes/year for 211 MW of firm capacity, roughly the amount of energy that the proposed wind project generates. Higher technology coal plants (~45% efficient and very clean), more efficient still, will reduce emissions by more than 0.35 million tonnes/year for the same amount of electricity generated by 845 MW of wind. As noted previously on this blog, many willing investors are anxious to make such investments. Only a perverse system of government permits and approvals and uninformed environmental groups stands between newer combustion technology and improved power supply. These are truly the “shovel-ready” projects.

The costs to the electricity consuming public for emissions reductions on the order of what is produced by the proposed Oregon wind plant are less than one half what will be required to keep the new wind project in operation and shadowed/backed up properly. An investment of a similar magnitude to the wind plant in high technology coal combustion, by replacing roughly 1,000 MW of older, less efficient, dirty coal generation capacity, would reduce emissions of CO2 (and a lot of other things like SOx and NOx and mercury) by more than 1.65 million tonnes annually, more than five times the emissions reductions that can be credited to the wind plants with the plus of a substantial improvement in grid reliability. Investing $1.9 billion in new high efficiency coal plant of 845 MW could replace older ones and reduce emissions considerably. Alternatively, such a plant would serve 600,000 additional household customers in the NW Power Pool or Southern California for about 6.5 cents/kWh, roughly one third the cost of wind, including its shadowing/backup requirements without the need to resort to arithmetic sleights-of-hand about reliability.

Conclusions

The considerations of wind availability, system operations and hydro availability are likely to be more complex than the treatment given here. However, a more complete system simulation is unlikely to be more favorable to wind than is the present treatment, especially if increased reliability standards are implemented for power pools. The proposed CO2 savings from the Oregon wind project are overstated to a significant degree and it is likely that net fuel/emissions savings will only be possible during periods of surplus hydro availability – the off-peak spring and fall seasons.

The lesson from this case is that reported claims of benefits from the introduction of industrial wind plants, such as, households served and CO2 emissions saved should be carefully reviewed – they are generally difficult to support.

And since wind competes with other projects for investment capital the funds that are devoted to wind may actually reduce potential emissions savings from efficiency and technology improvements in coal, improvements that can be supplied without tax credits or other fiscal chicanery.

With power grids strained due to heating demand, increments to generating capacity are to be welcomed. But along with the usual hoopla about homes served and CO2 emissions savings, it is time for some “devil’s advocacy” by asking: – how much energy and capacity will this project really create? How much CO2 will be saved? And when the chips are down will consumers and grid operators be pleased that their funds have gone into wind rather than into some other generating source?

We strongly suspect that neither consumers nor grid operators will benefit greatly from this plant. Our brief analysis of this announcement shows that the claims for houses served and carbon saved are not supported, though some incremental, useful energy supply may be possible under some circumstances. All such claims depend on the system operator’s ability to use the wind farms’ output to offset hydro generation, the key generation resource in the Northwest United States (NW).

Contributing to Capacity: The Sine Qua Non of Power Generation Investments

In the service area where the new wind project will be located, total generating capability is 84 GW. Hydro accounts for 60% of this total (nominally). Current peak demand in the NW power pool, into which the wind project will inject energy, stands currently at just over 60 GW, about the same size as the UK grid. In the winter season provisions for other claims on the water (irrigation, flood control, endangered species protection, etc.) reduce the available capacity of hydro by some 7 GW. The pool’s own capacity assessment notes that “A severe weather event for the entire Power Pool area will add approximately 6,000 MW of load while at the same time reduce [sic] the capability by 7,000 MW.”

In other words, when the chips are down, hydro’s contribution to meeting a larger peak demand may fall by as much as 7 GW, with another 6 GW less capacity from other generation sources. Let’s do the arithmetic: the “normal” winter peak (50% probability) is 61 GW, generating capability (not the same thing as firm capacity) is 84 GW. Comes the storm and the peak rises to 67 GW, while the “capability” falls to 71 GW, providing just a bit more than the minimum reserve requirement of 5 GW.

How likely is it that wind can add to capacity in the midst of a winter demand surge and capacity restriction?

From recent UK experience, not bloody likely. The following table was taken from the UK system operator website for the first week of January 2010; most days since the middle of December 2009, when winter weather gripped the nation, have looked similar.

The outstanding performer is gas-fired CCGT technology, ~34% of capacity and 38-40% of output. Coal and nuclear supply almost all the rest of the capacity and energy. So where is the wind? The UK, with more than 4 GW of wind generation capacity (~6% of total), saw essentially no help from wind in meeting demand during this entire period. With wind’s contribution to capacity ranging from just over 100 MW to about 500 MW for much of the crisis period, about a 2.5 – 9% capacity factor, and with wind’s contribution to energy at less than 1% for days on end, one would be hard-pressed to attribute much of a peak contribution to a large wind project in Oregon.

235,000 Homes Served? Is This Claim Likely or Even Possible?

The claim is that the project will provide enough energy to power 235,000 households. Assuming a generous capacity factor of 30 per cent this yields a reasonable average annual household use of:

845 MW x 1,000 (convert to KWh) x 0.30 x 24 (hours per day) x365 (days per year) / 235,000 = 9,450 KWh per household

A reduction in capacity factor to 25 per cent reduces the households served to about 176,000. Is this a reasonable consideration? Recent experience world-wide shows that capacity factors are often less than that.

But these calculations rely on a measure that reflects the aggregate annual consumption. A more realistic representation would be based on meeting the peak demand per home, which is estimated to be approximately 1.5 kW. How do wind plants perform on this basis? Using the more applicable measure of capacity value (sometimes called capacity credit and explained further below), the proposed project will theoretically generate enough energy to meet the needs of about 49,000 households, at a cost of more than $2 billion for initial investment. Over a 20-year lifetime that electricity will cost the NW Power Pool about 17 cents/kWh for “average” power, and some of the costs can be made to “disappear” through the use of state and federal tax credits and other subventions. It is not easy to calculate a “firm” supply cost for wind, given the absolute reliance on backup, but this is in addition to the above 17 cents/kWh. For the kind of money that wind costs the pool could supply diesel generators to neighborhoods for an investment of less than $600 million and contribute a firm 845 MW at about 20 cents per kWh (including fuel). Those diesel units could reliably meet the peak demand needs of more than 563,000 households as follows:

Given an average peak requirement of a household, equal to about 1.5 kW, and assuming a coincident peak, then a firm 845 MW of generation, as supplied by the diesel units, can meet the needs of about 563,000 households.

i.e., 845 MW x 1,000 / 1.5 = 563,333 households

Even using the possibility that some of the diesel units would be unavailable, probably 2-3%, the number of households that could be served at peak reliably would still be more than 546,000 (97% plant availability at peak).

Wind cannot be relied upon to provide firm generation at full capacity coincident with peak demand. Wind might be capable of contributing to the peak demand requirements of the system at some times. However, this will rarely happen, and when it does it will be for brief periods. In these circumstances, the expectation of the number of households served will be just over 49,000. To calculate this it is necessary to introduce the factor representing the statistical expectation of wind production at peak demand times. This is capacity credit, or capacity value, which brings a number of considerations into play, but typical experience, and the figure used by the Texas system operator, is 8.7 per cent.

i.e., 845 MW x 1,000 x 0.087 / 1.2 = 49,010 households

In spite of all statistical expectations of output from wind generators, these households will not be served reliably in any manner that meets their needs. Taking this out of the comparatively benign case of households, can you imagine a hospital, a school or a business relying on an electricity supply dominated by wind? Calculations that are based on aggregations summed over a year and averages do not reflect the real world, which operates in real time.

For significant periods of time, no households will be served, as was demonstrated by the UK data. For almost all of the time, the electricity supply will be so unreliable as to be useless. If there were some way to store the wind-plant electricity produced, then some of this would make sense. Even granting such a widely available storage capability, there would be considerations of the relationship between the storage being filled compared to the draw on it, again in real time. Annual aggregations and averages are not a reasonable way to look at the fluctuating performance of industrial-scale wind power.

The message that emerges from both the calculations and experience is that claims regarding homes served by industrial wind power are not valid measures of wind’s value. The true measure of value is the displacement of hydrocarbon fuel and reduction in CO2 output by the power generation system. As shown in previous articles, the need for shadowing and backup generation to ensure that load can be met despite fluctuations in wind output may result in little or no net decrement to fuel use or emissions.

However, our analysis shows that under some circumstances integration of industrial scale wind may permit small reductions in shadowing and backup fuel use, provided there is sufficient excess hydro capacity. For the Oregon wind farm case, wind would seem to be specifically excluded from meeting winter peak demand. However, wind may be able to contribute somewhat to meeting energy demand in the off-peak seasons.

In Part 2 we consider under what conditions and to what extent an industrial wind facility may save fuel or reduce CO2 emissions.

The most interesting story for 2010 is that the dash for gas in the U.S. has begun–again. In Part II or this two-part report, we will explore the challenges facing nuclear, coal, and renewable energy electricity sources in 2010 and beyond.

Business Climate–Energy Demand

As we enter the second decade of the 21st century and a second year of avoiding an economic collapse, the U.S. business climate seems to have become more positive. A growing sense of cautious optimism is appearing. A mid-October survey by the National Association for Business Economics concluded that the largest recession since the 1930s Great Depression is over, and economic growth is likely for the U.S. economy in 2010. The government announced that third-quarter 2009 economic growth hit 3.5%, the first positive growth in five quarters, suggesting an end to the recession (Figure 1).

Figure 1. Electricity growth resumes in 2010. After a two-year contracting market, total electricity consumption in the U.S. in 2010 is expected to increase. Source: EIA, November 2009 Short-Term Energy Outlook

The implications for electric generation are mixed. What gets built depends on a complex stew of credit markets, regulatory responses, economic growth, technology, and national politics. Some of those are leading economic indicators, some lagging, some not clear at all.

Renewable generation has not made a convincing economic case in the market. But politically it has the upper hand. Coal and nuclear continue to take a political battering at the hands of the renewables advocates. The politics of energy is being upended by new implications for natural gas. The political and regulatory landscape is a dog’s dinner (a Britishism for an undigested mess).

The need for new generation to supply load appears less urgent than in previous years. According to the EIA, demand for electricity has fallen since the economy tanked in 2008. The demand down-tick is the first since the EIA has accumulated these statistics in 1977.

Facing a sluggish economy, consumers have reduced thermostats, cut off air conditioning, and dialed down appliances, leading to the decline in electricity demand. A cool 2009 summer in most of the U.S. helped to reduce air conditioning load. Net electric generation dropped 6.8% from June 2008 to June 2009. That was the 11th consecutive month that electric generation slid downward, compared to the same month in the prior year.

Analysts say they expect the declining demand trend to reverse when economic growth shows up at the beginning of 2010 or thereabouts. But they have been wrong before and may be wrong again. The EIA, the U.S. Department of Energy’s statistical agency, says it suspects the decline in demand will continue into early 2010, despite what appears to be a bottoming-out of the recession.

Many electric power company long-term capital spending plans have been built on the dire forecasts of the past decade, particularly from NERC. For years, the conventional wisdom in the generating industry was that the U.S. was running out of generating capacity. Year after year NERC had the same message: It’s time to build baseload, particularly nuclear and coal, and make major investments in high-voltage transmission.

Maybe not. Intermediate-load and peaking units, suggesting new gas plants, may be the ways to hedge big investment bets on future baseload units. A recent Washington Post article quoted anonymous sources as saying that new nuclear plants aren’t economical until natural gas prices are above $7/mmBtu. That’s more than double the current price.

The urgency for long-distance, high-voltage electric transmission investment, premised on optimistic estimates of growth in demand, also seems to have declined. Capital requirements for the big transmission projects, along with the political risks, have scared off investors, including conventional utilities and free-standing investment companies. Those who want to build large transmission systems linking areas of surplus power generation (West Virginia, for example) to big markets in New Jersey and New York are facing not only citizen opposition but also indifference from Wall Street investors, who don’t see an acceptable market return on investment (Figure 2).

Figure 2. New transmission is key in future years. The North American Electric Reliability Corp. predicts that expanding critical transmission capacity will be a national priority over the next five years. Source: NERC

The bullish generating market in late 2008—despite signals of a worldwide economic crisis—turned into a financial quagmire. Today, lenders are unwilling to pony up cash for new generation and transmission without guaranteed returns, regulators are reluctant to bless projects without iron-clad promises of stable prices, and customers are unwilling to support new projects that threaten rate hikes and environmental impairment. Governments at the federal and state level are demonstrating distinct ambiguity about generation and transmission projects.

Where does that land us? Overall, the generating market has slowed. Raising credit has become difficult for major projects of any kind, from new nuclear reactors to petroleum refineries to coal mines. Money wasn’t a problem a decade ago. Today, it’s a big problem. Tomorrow, meaning 2010 and beyond, that may change. But don’t bet the company. It’s a jungle out there.

The Political Environment for Power

After a year with a new political crew in Washington—Democrats in the White House and controlling both the House and Senate—how has the political landscape for electric generation changed? It’s not clear. Democrats have said they want substantial reforms in the way the nation addresses energy, including the alleged specter of climate change. The party, including the Obama administration, is pushing legislation in Congress that appears unlikely to be enacted this year.

Complicating the administration’s policy agenda, the political clock has already started ticking toward the 2010 mid-term elections, when all of the U.S. House and a third of the Senate seats are up for election. Traditionally, the party in power loses seats in off-year elections. The Obama administration likely will take heroic steps to prevent that outcome, particularly to ward off losing the Democrats’ 60-40 margin in the Senate, where it takes 60 votes to avoid a filibuster. Ducking a filibuster is a prerequisite for passing Senate legislation in these days of total partisan warfare.

In that context, what has changed since 2009 when it comes to energy legislation and the economic prospects for energy development? Paradoxically, very little. The administration promised new directions in energy, with an emphasis on controlling greenhouse gas emissions and increasing energy efficiency, without much in the way of specifics. The Obama administration attempted to create a dramatic picture of how it differed from the Bush administration. The optics succeeded, but the reality is far less than meets the eye.

The Obama administration’s position on energy legislation is not very different from that of its predecessor. Both offered generalities and platitudes but not much practical red meat. The current administration has largely stayed away from the legislative details of climate legislation (as it has done with health care). The House passed a cap-and-trade bill (Waxman-Markey) that takes the approach that if the policy causes you any pain, we will pay to make you feel better. Republicans correctly call the House bill “pork” but have had nothing to offer in response.

The Senate Environment and Public Works Committee bill is not much different than the House-passed measure and leaves many details to be fleshed out in markup in the committee, chaired by California Democrat Barbara Boxer, an enthusiast for measures to control greenhouse gas emissions. Republicans have indicated that they will be unanimous in attempting to block the bill. The GOP may be able to pick a few Democrats to oppose the Boxer bill, dooming the legislation. In November, the Democrats reported out the committee bill, without Republican participation, as the GOP boycotted the committee markup session. That does not bode well for legislation anytime soon.

The Senate Energy and Natural Resources Committee, chaired by New Mexico Democrat Jeff Bingaman will also have a powerful legislative and political oar to dip into energy policy waters. Bingaman’s state is a major producer of coal, natural gas, and uranium, but it is a minor state when it comes to electricity production. How he will approach the greenhouse gas issues is not clear.

Four more Senate committees will have a say in the final legislation. Energy politics tend to be regional, not ideological, as both parties are prepared to spend taxpayer dollars for fuels and technologies that touch their constituents.

The legislative fight could carry deep into 2010 without resolution.

Record Gas Reserves Discovered

“Holy cow, there’s a lot of gas.”

That was the reaction of Penn State geologist Terry Englander, as reported in the Massachusetts Institute of Technology’s Technology Review last October. Three years ago, Englander was asked to assess the natural gas potential of Marcellus shale deposits in the U.S. Midwest and Mid-Atlantic regions. It now appears that deep shale beds—the Carboniferous (350 million years ago) Barnett shale deposits in the Texas and the enormous Devonian (400 million years ago) Marcellus shale deposits in the East—could be game-changers in the U.S. energy and power generation markets for years to come.

Shale formed in those deposits contained methane bound so tightly into the rock formations that conventional drilling technology could not get at it, according to the geologists. That’s changed. Deep drilling, horizontal drilling, and hydraulic fracturing (pumping water down the borehole at great pressures to shatter the shale strata, releasing the methane from the rock) make the gas accessible. Both shale finds are providing drillers with gas bonanzas.

Last June, the U.S. Potential Gas Committee (PGC) issued a report that estimated total U.S. natural gas reserves at over 1,800 trillion cubic feet, the highest in the committee’s 44-year history, and 40% above its 2006 estimate. John Curtis of the Colorado School of Mines, head of the PGC, said that the estimate “reaffirms the committee’s conviction that abundant, recoverable natural gas resources exist within our borders, both onshore and offshore, in all types of reservoirs.” Prices fell, reflecting the optimistic supply predictions. Exploration in shale deposits continued growing.

The PGC is an independent, industry-funded technical group that examines natural gas reserves in the U.S. Said Curtis, “Our knowledge of the geological endowment of technically recoverable gas continues to improve with each assessment. Furthermore, new and advanced exploration, well drilling, and completion technologies are allowing us increasingly better access to domestic gas resources—especially ‘unconventional’ gas—which, not all that long ago, were considered impractical or uneconomical to pursue.” That’s a reference to shale gas, as well as gas in deep deposits.

Significantly, the shale gas deposits are close to, and in some cases, directly underneath, natural gas pipelines and gathering hubs and near large markets. Bringing the gas to market could be easy and cheap.

In a press release, the PGC noted, “When the PGC’s results are combined with the U.S. Department of Energy’s latest available determination of proved gas reserves, 238 Tcf [trillion cubic feet] as of year-end 2007, the United States has a total available future supply of 2,074 Tcf, an increase of 542 Tcf over the previous evaluation.”

That’s a stunning figure—an increase of over 25% above previous estimates. The Energy Information Administration (EIA) defines “proved reserves” as “those volumes of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.” In other words, they are real.

The supply optimism is good news for existing and potential electric generators, as the projections, bolstered by successful drilling in shale, have resulted in dramatically lower natural gas prices. The most recent reports from the EIA found natural gas prices at the Henry Hub at $2.76 per million Btu (mmBtu). Futures prices at the New York Mercantile Exchange for September 2009 contracts were at $2.91 per mmBtu. A couple of years ago, the NYMEX price was in the $9 range for short forward contracts (Figure 3).

Figure 3. Gas prices expected to stabilize in 2010. The U.S. Energy Information Administration (EIA) predicts natural gas prices will fluctuate less and be more predictable in the future given the significant increase in gas reserves. Source: EIA November 2009 Short-Term Energy Outlook

Say Goodbye, LNG?

Among the implications of the optimism about shale gas recovery in the U.S. is a crash landing for plans to build imported liquefied natural gas (LNG) terminals in the U.S. Three years ago, LNG was the rage of the age, with predictions of terminals across the coastal U.S. Daniel Yergin’s Cambridge Energy Research Associates (CERA) was bullish on LNG, predicting a worldwide LNG boom.

No longer. No recent publicly available material on LNG has shown up on the CERA web site, although there was reporting available to paying customers (the price tag is very high). Could the consultancy’s enthusiasm for LNG have cooled considerably on current and projected natural gas prices? The guess here is that it has.

On the other hand, CERA’s web site now touts shale gas, saying, “Some call it a revolution,” adding that shale gas “could change the global natural gas balance.”

To date, according to the Federal Energy Regulatory Commission (FERC), four new LNG terminals are under construction in the U.S., with just under 4 billion cubic feet of gas capacity. Three of the four are in the Southeast or Southwest, where they serve petrochemical plants. FERC has approved another 14 LNG projects for the U.S., but analysts expect few of those will actually see the light.

Summarizing its most recent data, the Energy Information Administration (EIA) said, “In 2008, increased U.S. natural gas production led to reduced demand for natural gas imports. The drop in total imports occurred despite a 2007-to-2008 increase in domestic consumption—a factor that typically requires higher levels of imports to meet consumer demand. Total exports to Mexico and Canada via pipeline and Japan via LNG tanker were higher in 2008. Consequently, net imports to the United States fell more than 20 percent from 2007 totals to the lowest level since 1997. The decline in U.S. natural gas imports had a larger impact on LNG imports than Canadian pipeline imports. Given the ease of transporting gas to alternative markets, some LNG that historically landed in the United States went elsewhere in 2008.”

The EIA went on to say that “The increased supply of LNG brought about by the start-up of several large LNG supply projects in late-2009 and in 2010 contributes to an increase in the outlook for U.S. LNG imports next year. However, the timing of these new liquefaction additions is extremely difficult to judge.”

Favorite Power Generation Fuel Returns

For 2010, gas sees its prospects gaining in the power market, bolstered by new technology and large new supplies. The leader of the generating pack in the 1980s and early 1990s, gas went into a deep decline on high prices and diminishing reserves in the first part of the 21st century. Many analysts said the days of gas as a major generating fuel were over.

No more. Given that gas is less polluting than coal (by any measure), produces half as much carbon dioxide (CO2) per unit of energy output, and requires plants that are quick to build and not capital-intensive, new gas reserves appear to position the fuel as a winner in generating markets. The U.S., once seen as a declining gas producer, may be a world leader in gas.

In November, The Energy Daily reported that the North American Electric Reliability Corp. (NERC) has found that “Electric utilities are increasingly showing an ‘overwhelming’ preference for building natural gas–fueled plants, a trend that is expected to drive gas past coal as the dominant North American fuel for on-peak power production by 2011.” According to the newsletter, “NERC said both regulated utilities and merchant generators are increasingly favoring gas plants because the fuel has been discovered in more abundance and is cheaper than in the past. In addition, gas plants are easy to site, can be built quickly and produce less carbon emissions than other types of traditional generation.”

This overabundance of natural gas reserves may also have a downside, according to a report released by NERC on October 29. NERC’s “2009 Long-Term Reliability Assessment 2009–2018” report notes that natural gas–fired on-peak power production may push past coal-fired generation by 2011, portending system reliability problems. NERC also cited cyber-security concerns, the integration of fast-growing renewable resources into the grid, and uncertainties created by the economic slowdown as emerging reliability worries that it faces (Figure 4).

Figure 4. Demand for electricity will rise in 2010. The top figure describes the expected growth of capacity that will be available during peak hours. The bottom figure describes the expected growth of installed capacity. Coal and gas will continue to be the fuels of choice during peak generating hours. Wind generation will continue to grow faster than any other but will contribute little to peak supplies. Source: NERC

NERC recognized that existing reserve margins are adequate across the U.S. for the next few years, but the first priority must be to expand the grid and increase the capacity of existing transmission and distribution systems to handle the expected growth of renewable generation. The report concluded, “More than 11,000 miles (or 35%) of transmission (200 kV and above) proposed and projected in this report must be developed on time to ensure reliability over the next 5 years. 32,000 miles of transmission (200 kV and above) are projected for construction from 2009 to 2013 overall.” NERC strongly believes that transmission siting and construction is the most urgent issue for the power generation industry, now and well into the future.

Electricity growth has stalled over the past two years, given the chaos in the global economy. However, NERC projects that demand will increased 15% between 2009 and 2018, compared to its 17% forecast in last year’s report. The projected demand increase has steadily decreased over the past several years. Once again, NERC underlined the need for grid expansion and new transmission capacity to handle renewables and ensure reliability, with particular urgency seen in areas of the Southwest.

“These competitive advantages have resulted in an overwhelming preference for electricity over the ten-year period, as installed natural gas capacity is projected to increase 38 percent over the ten-year period, while coal is projected to increase by only 6 percent,” NERC’s assessment said. Its predictions of demand for new generation have been overly generous in the past but now appear to be more realistic (Table 1). The EIA predictions of electricity demand growth do not include peak demand growth as a separate category, but rather predict energy consumption will grow 8.2% through 2018. Together, the NERC and EIA data clearly show that the need for additional, dispatchable load during on-peak hours will be a primary focus for electricity system planners. Expect more gas-fired reciprocating engine and combined-cycle plants designed for intermediate peaking service to be announced in the coming year.

Table 1. Electricity use increases, slowly. The North American Electric Reliability Corp. (NERC) expects the rate of peak demand and energy consumption growth to slow in coming years. Source: NERC

Further, NERC said that “on-peak natural gas capacity is projected to grow by more than double the amount of any other resource, and by more than five times any other resource when dual fuel resources (primarily fired by natural gas and another, alternate fuel) are excluded.” NERC said a “plausible” future scenario involves flat or negative power demand growth for the next seven or eight years, followed by an “abrupt change to normal or high demand growth.”

From NERC’s perspective, however, that trend is not all good. NERC said the growing reliance on gas could create grid problems if gas usage strains the infrastructure that delivers gas to power plants. “The projected growing reliance on natural gas increases the potential for adverse reliability impacts due to fuel supply and storage and delivery infrastructure adequacy issues,” NERC said.

Increased gas demand this past summer already put a strain on existing gas transmission infrastructure. Chesapeake Energy Corp. admitted that it briefly slowed production because natural gas pipelines and gathering systems were already operating at maximum capacity (Figure 5).

Figure 5. Gas storage and pipelines full in 2010. An excess of natural gas is packing gas lines and storage facilities. Shown is the predicted rate of natural gas storage for 2010 compared to historic amounts. Source: EIA November 2009 Short-Term Energy Outlook

Unexpected Trend: Fuel Switching

When the Acid Rain Program under the Clean Air Act took effect in 1995, utilities searched for ways to avoid installing expensive flue gas desulfurization systems. One approach much favored by plants in the eastern U.S. was to perform a boiler fuel switch from high-sulfur eastern bituminous coal to low-sulfur Powder River Basin coal. A side benefit was that the coal was significantly less expensive to purchase, even if the delivery charges were much higher given where the coal is mined. Today, with the nation expected to be awash in natural gas, several utilities have announced plans to, in essence, fuel switch from coal to natural gas.

A good example is Progress Energy Carolinas’ August announcement of its plans to permanently shut down three coal-fired power plants near Goldsboro and, in exchange, construct a new, high-efficiency, gas-fired 950-MW combined-cycle power plant. The business case for the fuel switch is compelling. The utility gets bragging rights, not to mention emissions credits, for shuttering three coal plants totaling almost 400 MW at the H.F. Lee Plant in Wayne County. The utility makes a compelling case that its plan will reduce overall emissions (including those of CO2, should carbon controls eventually become law), increase the efficiency of electricity production in its system, and, if natural gas prices remain low, lower the cost of electricity production. The cost of the new intermediate-load plant, expected to be in service by 2013, is estimated to be around $900 million.

A final advantage to Progress Energy: Adding a natural gas–fired plant will broaden the company’s fuel resource base away from coal and nuclear. As a side benefit, shuttering the older three plants sidesteps the requirements of North Carolina’s Clean Smokestacks Act, which established very aggressive emission-reduction targets in 2013. Instead of cleaning up the old plant, Progress Energy decided it was wiser to invest the money in a new plant.

“This is an important milestone for our company and for our state,” said Lloyd Yates, president and CEO of Progress Energy Carolinas. “The Lee Plant has been producing electricity reliably and cost-effectively for our customers for more than 50 years, but as emission targets continue to change, and as legislation to reduce carbon emissions appears likely, we believe in this case, it’s in the best interest of our customers to invest in advanced-design, cleaner-burning generation for the future.”

Yates went on to say, “Our objective is to maintain the right balance of resources—nuclear, natural gas, coal, hydroelectric, solar, biomass, and energy efficiency—to make our company and state more energy independent and to minimize the risk of customer price spikes due to volatility in cost or supply of any single fuel source.”

The economic advantage to Progress Energy is apparent, but in an unusual display of harmony, North Carolina regulators have disarmed all the explosives in the usual regulatory minefield encountered when permitting a new gas plant. The North Carolina General Assembly recently approved legislation to facilitate a fuel or technology replacement project as Progress Energy has proposed. Senate Bill 1004 established a streamlined certificate process (45 days versus the standard six months or more) to enable Progress Energy to shut down the coal units and replace them with natural gas–fueled technology. The shorter certification period was needed to enable the company to replace the coal-fired plants by 2013, when the stricter statewide emission targets come into effect.

Expect additional state legislatures to quickly open an express lane for permitting gas-fired combined-cycle plants that replace older, less-efficient ones. Utilities will quickly respond to this economic carrot faster than the regulatory stick.

The second emerging fuel-switching trend is retooling a coal plant to burn other fuels in order to help meet state renewable portfolio standards and to avoid costly emissions equipment retrofits.

The most interesting project in this genre of plant makeovers is FirstEnergy Corp.’s plan, announced in April, to repower two units at its R.E. Burger coal-fired power plant to burn biomass. Those two coal-fired units, totaling 312 MW, would become the largest biomass power plants in the U.S.

Burger Units 4 and 5 were targeted by the Environmental Protection Agency for alleged violations of the Clean Air Act’s New Source Review provisions. A consent decree signed in 2005 settled those charges but gave FirstEnergy until midnight March 31 to decide whether to shut down the units or agree to retrofit with expensive air emission control equipment estimated to cost $330 million. Instead, the utility decided to invest $200 million to convert the two units to burn biomass. The fuel switch also furthers FirstEnergy progress toward meeting Ohio’s standard that requires utilities to obtain 25% of their power from renewable resources—at least half of which must be generated within Ohio.

According to First Energy, the two Burger units will use wood wastes and other biomass to fuel the facility. FirstEnergy’s goal, however, is to operate the plant as a “closed loop” or carbon-neutral biomass plant, which means it will use fuel derived from trees grown to serve as feedstock for the biomass. The energy crop trees would act as a carbon sink, storing carbon in the trees’ tissues and roots.

When harvested and burned, the stored carbon would be released, but the net carbon footprint would be zero. Fast-growing, bioengineered cottonwood trees and grasses grown in Ohio will be harvested and pressed into cubes before delivery to the plant. The plant will then pulverize and blow the biomass fuel into the boiler in much the same way as coal plants use pulverized coal.

A number of other utilities have announced similar plans to retrofit fossil-fueled plants to burn biomass fuels. Over the past three years, Southern Co., Northeast Utilities, Dynegy, Xcel Energy, and DTE Energy have either converted plants or are in the process of doing so.

More to Come
In Part II, we will predict what the future holds for the remaining fuel-source power generation technologies (nuclear, coal, and renewables).

—Dr. Robert Peltier, PE is editor-in-chief of POWER. Kennedy Maize is Executive Editor of MANAGING POWER

Gosh, Tom, I suppose that the pace of global warming has accelerated in the last decade, and hurricanes are getting more frequent and stronger too. And those emails from the alarmist in-crowd that the climate world (and general public!) are reading about right now–those are the good guys, the real disinterested scholars at work.

So, Tom, you claim that cap and tax opponents are calling forth a mass plague–a modern Black Death–that will wipe out 2.5 billion people sometime between now and 2050. (Well, I guess this simply extrapolates what John Holdren is postulating by 2020–a possible billion deaths!)  In your world that is an inevitable result of modern living using hydrocarbon fuels.

Unlike his imaginative colleague Maureen Dowd, what Tom Friedman writes actually matters.  Many people believe that he is proficient about energy and climate. So I must again call this charlatan to task.

A Gulfstream Malthusian

As we have seen, Friedman’s musings on energy and climate don’t stand up very well to actual events, data, or logic.  Or as the courtroom wag once put it: if you have the facts, argue the facts, if you don’t have the facts argue the law, if you have neither pound the table.   Tom is pounding the table on energy and environment, accusing those who oppose his pet legislation of wishing a dreadful calamity upon mankind.

Unlike Thomas Friedman I actually know people who oppose the cap and tax monstrosity, and there is not a Malthusian among them; and not one wishes a return of the plague.  I challenge you to produce more than one or two kooks who happen to oppose cap and tax and who also wish a plague on the human race (contact me here for the terms of the bet).  As Friedman surely knows, the Malthusians are pretty much confined to their own loony corner of the left.  Oh, and you can always identify the Malthusians at the airport, they are ones headed for the Net Jets terminal (from their 20,000 sq ft homes).

Indeed, unlike the Malthusians, who wish developing countries to stay that way, preferably forever, the “bad people” who oppose cap and tax actually wish to see the Indians, Zambians, Peruvians and whoever else gain as much access to modern technology, including energy, as they can produce, purchase and create.  Not from us is the message that the world cannot afford for developing countries to access modern energy.

Renewables as the New WPA? Or Is There Some Other Point to All This?

Point one of Friedman’s “thesis” is that the globe is getting crowded and we cannot therefore provide energy for all of these people the way we do now.  Let’s stipulate that your assumption about crowding is correct.  So why would we choose, on an increasingly crowded planet, to use land-hog energy technologies – wind, solar and biomass – rather than using compact fuels and prime movers; we know them as oil and gas engines and power plants.  As recent articles on wind have increasingly shown, deployment of wind energy to an extent that can make an actual contribution to supplies, uses (and spoils) vast tracts of our countryside, and does not really reduce emissions much.  But to Friedman, we need this renewable energy because otherwise we will create so much pollution that the next 2.5 billion inhabitants of earth will die (that’s where the plague nonsense comes from).  Well, anyone who was alive in the US in the 1960s remembers what the air and water looked like then.  We invested a lot of money in clean up and the air and water in the US are far better now than they were in 1965 with half the population and less than a quarter the real GDP.  Everywhere you look rich countries are clean countries – air, water food.

Point two has something to do with making sure the US is the leader in renewable energy or otherwise we will be forced to despoil our land with useless renewable energy conversion devices manufactured elsewhere, or something like that.  My colleague, Marlo Lewis, has addressed this particular gem of incoherence.  He rebuts the idea that leadership in renewable energy is essential for the future by noting that:

1. Renewable energy generally destroys wealth, therefore the more of it you have, the less of anything else you can have (or, as the Eagles put it – you can spend all your time making love, or spend all your love making time);
2. Wind and solar do not reduce emissions much since they are intermittent and require hydrocarbon backups;
3. Renewable energy jobs require external cash infusions, and therefore are not actually self-sustaining

Point three is posterity.  According to Friedman our children will not be able to afford to live well since energy will have become so expensive.  That is an almost perfectly self-fulfilling prophecy should we be so foolish as to follow Tom Friedman’s recommendations for our new energy sources.

Sure, energy will become really expensive if (i) you prohibit the production of economical forms of energy, such as domestic oil and gas; (ii) you force us to purchase very expensive and unreliable energy from wind; (iii) you jack up the price of the “legacy” energy output of coal and gas plants with carbon taxes; (iv) you prohibit the deployment of advanced combustion technologies for coal that reduce carbon (and other) emissions by 15-35%; and (v) you have missed a massive revolution in US energy supplies, brought to us by hydraulic fracturing of shale gas reservoirs.

Gas is Energy’s Rodney Dangerfield – No Respect from Friedman

Somehow, the US Congress in its cap and tax extravaganza, the NY Times Foreign Affairs Correspondent, and many others have managed to miss the biggest development in domestic energy supplies in the last 40 or 50 years.  What Tom Friedman does not know is that the US has gone from a gas have not, with just 15 years of reserves, to a gas giant, with more than 100 years of gas supplies, due largely to new technology to exploit shale gas deposits.  Tom, you need to read your own paper.  They have had this issue covered for more than one year.

With enough natural gas reserves to maintain current levels of gas use for another hundred years we have lots of time to figure out what comes next, and to figure out how some of the wealth created thereby can be reinvested in new energy sources that actually produce net wealth for our country.  Natural gas plants are compact (hits that crowded thing, Tom), fuel is domestically sourced (so much for the people who hate us supplying our energy), the fuel is clean (no plague there), and they are reliable – can you say that for wind and solar?

Of course, you might try to sabotage the gas bonanza to make renewable more attractive, the Governor of New York has already tried.  Apparently someone explained the facts of (re)electoral life to him.  For you, elementary economic common sense should suffice.  And common courtesy, too.

Source: US DOE, for better map resolution

All those red lines running Northeast-to-Southwest carry gas from Russia to the EU countries.  There is just no getting around the Ukraine for most of the transits; it is big and (if you are Russian) in the wrong place.

Gas: The Great Green Hope for Europe

As noted previously, gas use in Europe is roughly the same as that of the US, a bit over 20 tcf annually.  Unlike the US, gas production in Europe is falling not rising, with net imports currently at about 10 tcf/year and going up by 0.5-1 tcf annually.  Russia provides about 80% of Europe’s imported gas (about 80%), with the remainder mostly arriving in the EU as LNG.

As coal-fired power plants face increasing environmental opposition, and as a new generation of nuclear plants proves difficult to finance and construct European nations have turned increasingly to gas.  Power generation in the EU currently uses about 6 tcf/y, about the same as the US, and the US Department of Energy expects this to rise to the 6.5-7.5 tcf/y range by 2015-2025.

With falling conventional production and limited import alternatives, Russia looks to maintain its key role in EU gas supplies in coming years.  For all of the touted alternative routes and sources – Nabucco, trans-Med pipelines, LNG – the EU remains wedded to Gazprom.  In fact, Russia has made a play for even greater EU dependence with its Nord Stream (Baltic) and South Stream (Black Sea) pipelines.  Completion of those two lines will permit Gazprom to supply Germany, Austria, Italy and others without transiting Ukraine or Poland.

Energy Security or Energy Hardball – Why spend all that money for half-full pipelines?

Russia will invest more than $40 billion in new pipeline capacity without any substantial increase in its gas exports to Europe.  Why?  One view is that it is all about control:

South Stream will cost upwards of $20bn to build, adding to suspicions this is politically rather than financially motivated project. “The Nord Stream and South Stream pipelines are designed as bypass pipelines without increasing Russian exports or improving the security of gas supply to Europe. On the contrary, these projects are designed to reduce the security of supply to Belarus and the EU member states of Germany, Poland, Hungary, Romania, Bulgaria and Greece. Russia will be able to turn off the gas flow to any of these countries without decreasing other exports,” Mikhail Korchemkin, executive director of East European Gas Analysis.

As for Nord Stream, it will supply Germany and Scandinavia with about 1 tcf/year, but this $20 billion plus project will not result in greater net Russian Exports to Germany.  In fact, field development costs for new Russian supplies are expected to be among the most costly options for new EU gas supplies (Riley, et al page 8).

According to knowledgeable analysis of Russian gas, the key to the viability of the two pipelines is that they permit France and Germany (investors in South and Nord Stream, respectively) to keep their domestic gas markets closed and will insulate them from Russia’s disputes in it “near abroad.”  Without liberalization in those two markets, the impetus of significant alternatives to “High North” (Yamal, Shtokman) gas supplies is limited.

So, what is going on here:  no new gas supplies, lots of spare pipeline capacity, the ability to bypass Eastern European consumers with bad attitudes, and guaranteed consumers for the next round of Arctic gas.  This sounds a lot like market control through vertical integration.  Plus you get to stick it to the Poles and the Ukrainians.

Just in Time for Winter: Russia Practices Invading Poland and Russia Announces “Problems” in Supply Through Ukraine

And right on cue the president of the EU (a Swede, not that “stiff-necked” Vaclav Klaus from the Czech Republic) has promised that he had “followed this issue closely and that we will continue to do so.”  We pretty much know how this play will end – supplies will be cut sometime after Christmas, in a very cold week, perhaps there will be kinetic problems with the pipelines, and then the EU, Russia, Ukraine will come up with a “solution” one that is likely to involve lending Ukraine enough money to pay its disputed bills to Russia.  And we will be happy for another year.

Only Mr. Market Can Face Down the Bear

As U.S. experience with deregulated gas markets and shale gas development have shown, even a small effort to produce energy economically can yield great benefits in the overall energy market.  Europe’s heavy investment in renewables, especially wind, has not produced these kinds of market effects because (1) they replace far less firm energy than predicted; and (2) the cost of energy from these sources is very high, providing cover for high gas prices linked directly to crude oil prices.

The U.S. is now in a strong position vis-à-vis LNG suppliers because the country has another source of energy that is fully substitutable and cheaper.  As we noted in our discussion of shale gas in Europe, “negotiating with Russia for lower gas prices by resorting to more costly forms of alternative energy, [such as offshore wind,] is like shoveling money into a furnace to prove that you have another way to heat your home.  You are not likely to get the best price.” [or a warm house]

In addition to the pricing aspect of limiting supply in gas competition, there is also the political problem that such monopolistic supply can create.  Would we really expect France, Italy or Germany to challenge a restriction in Russian gas supplies to one of the smaller Central European EU member countries if Russia retained the capability to retaliate against any one of these nations individually?  After all, what is all that excess network capacity for (pp 14-15) if not to move gas around to your friends and punish your enemies, all the while maintaining high price levels for gas.  As the noted Russia energy analyst, Anders Aslund, put it in 2006:

Naturally, Gazprom wants to maintain and if possible extend its monopoly over gas pipeline transportation. It wants to take over trunk pipelines in other countries, and it works hard on doing so. Gazprom and thus Russia are dead against the European Energy Charter and its Transit Protocol, because it will reduce Gazprom’s monopoly powers. In this regard, Gazprom and the European Union have contradictory interests. For years, the European Union has demanded that Russia ratify the Energy Charter, but Russia will never do so. (ibid)

Europe’s energy salvation does not lie with stifling competition in the name of “security.”  The EU would gain a lot more from encouraging production of its own shale gas resources, currently estimated at 300-570 tcf, than they would from “security” at a premium price.  With LNG prices low, this is also a good time to build up import and storage capabilities.  In energy markets a little bit goes a long way.  The 1979 price quadrupling was caused by a cutback of less than 5% (Iran) in world oil supplies.  The recent 10% increase in U.S. natural gas production (about 3% of total domestic energy production) has weakened LNG prices worldwide greatly benefiting gas users more than any conceivable alternative energy project.  Small changes at the margin can be significant.

This would be an excellent time for the EU Competition Commission to hold firm in its support for liberalized markets in energy.  If Europe could get 1-2 tcf/year from its shales, 12-25% of what the EU now imports from Russia, another 1-1.5 tcf from Algeria and Libya, and more LNG to balance load then Russia would be forced to negotiate about the economy of its gas, instead of the political economy of its gas.

Editor’s note:  This article is the second of two on shale gas production.  The first dealt with the U.S. situation; this one looks at the potential impacts of shale gas production in Europe and China.

Natural gas production in Europe, currently just over 11 Tcf, has been falling rapidly over the past decade.   About three fourths of Europe’s gas is produced in just three countries: the UK, Norway and the Netherlands.  Production peaked in 2003 at 13.5 tcf.

Consumption, on the other hand, continues to rise.  Gas use in Europe stood at 20.5 tcf in 2008 and is likely to increase further as coal-fired power plants retire or are phased out of service for environmental reasons.  Most of Europe’s imported gas comes from Russia (about 80%), with the remainder mostly as LNG.

Conventional natural gas production is likely to continue its decline since the major source of gas production, the North Sea, seems set on a declining trajectory.

A Scramble for Supplies Seems to Be in Order

With the continent increasingly dependent on the state of Russian-Ukrainian relations, and with Russia’s sales prices pegged directly to oil, Europe’s energy future promises to be even more costly than its past.  Recent efforts at diversifying supplies – LNG, Nabucco, pipelines from Libya and Algeria – have proved only partially successful and retain the oil-linked price structure of Russian gas supplies.

Gas from Shale, Ours and Theirs, May Rescue Europe

U.S. shale gas production has already roiled the world of natural gas.  By providing plentiful supplies to the US shale gas production has promoted heavy discounting of natural gas in the U.S. relative to oil.

In addition to the U.S. consumers who benefit from lower natural gas prices, the shale gas boom has also provided new investment and technology opportunities for both US and European energy companies.  European consumers of LNG have also benefitted from the U.S. shale boom since prices for spot cargoes have fallen with the near-collapse of growth in the US market for LNG.  The main losers from the shale gas boom have been LNG exporters and renewable energy producers who must compete with natural gas in the electricity market.[i]

The list of major foreign investors in US shale gas plays is impressive – Norway’s Statoil in the Marcellus shale, British Gas in the Haynesville shale, Shell in the Fayetteville shale.  Total has purchased significant acreage in its home country, where drilling is set to commence.

With the technological risk of shale gas production now largely overcome thanks to efforts in the U.S., production is mostly a question of finding the right resources.  Major companies, flush with US shale gas experience (and profits) are now looking at Europe.  As with the U.S. earlier in this decade, Europe’s gas markets reflect scarcity with high prices.  However, mud (the stuff of shale deposits) appears to be much more democratically distributed than oil and shale resources have been discovered throughout Europe.

Estimates of the potential shale reserves in Europe reflect the early stage of exploration and test drilling.  However, activity is brisk in Poland (Lane Energy and Conoco), Hungary ExxonMobil), Austria (OMV) and France (Total).  Even the Netherlands is getting another look underneath the old Groningen gas field.  In the UK’s Permian Basin shale deposits may see some exploratory activity soon.  One of the best recent sources on European shale gas resources is a study of shale reservoirs in Europe by Hans Doornenbal, et al, “Petroleum Geological Atlas of the Southern Permian Basin Area: Project overview,” June 2009.  That study estimates at least 230 tcf of gas in NW Europe’s shale basins.  Other estimates are higher, as much as 500 tcf.  Such reserve estimates are not likely to produce the level of output seen in the US, where the resource base is far greater.  However, without drilling the resource extent is not entirely certain.

Only Mr. Market Can Face Down the Bear

As U.S. experience has shown, even a small effort to produce energy economically can yield great benefits in the overall energy market (economists call those pecuniary externalities, reflecting the normal balance of winners and losers in a competitive market).  Europe’s heavy investment in renewables, especially wind, has not produced these kinds of market effects because (1) they replace far less firm energy than predicted; and (2) the cost of energy from these sources is very high, providing cover for high gas prices.

The U.S. is now in a strong position vis-à-vis LNG suppliers because the country has another source of energy that is cheaper.  For the Europeans, negotiating with Russia for lower gas prices by resorting to more costly forms of alternative energy is like shoveling money into a furnace to prove that you have another way to heat your home.  You are not likely to get the best price.

In 1979 a shortfall of less than 5% of crude oil production for a few months (the Iranian revolution) caused the price of crude oil to triple.  In 2008-2009 a 10% increase in U.S. natural gas production (about 3% of total domestic energy production) has wreaked havoc on world LNG markets.  Small changes at the margin can be significant.  If Europe could get 1-2 tcf/year from its shales, 12-25% of what the EU now imports from Russia, then Russia would be forced to listen, the world would become a better place (unless, of course Russia resorted to alternative methods of business negotiation) and the continent’s expenditures for clean energy could start to fall.

Even China has caught the shale bug.  Some gas-bearing shales have been discovered in Xinjiang province and exploration and development will commence during this year.  Since China is a growing importer of LNG, and soon, gas by pipeline from Russia and Central Asia, economical production of gas from shale deposits would exert a price-constricting cold shower on both LNG markets and Russia’s gas exports.

More gas at reasonable prices would be considered by most people to be a good thing.  But not to worry, the sackcloth and ashes crowd still hopes to nip this “problem” of shale gas in the bud.  With enough legal opposition and red tape perhaps shale gas can be consigned to the curiosity corner of energy history, or we can let willing investors and willing buyers run with it and change the world.

The Bottom Line
Will gas from shale end the era of coal? Not anytime soon. Nor will the shale gas revolution permit a vast expansion of gas use for vehicle fuels, à la the Pickens Plan. As with coal-fueled power plants the amounts of gas available from shale are not sufficient to be “the solution.” There is no single solution to energy supply, but gas from shales can fix the gas market, and that would be a real accomplishment, reducing the power of some of the would-be gas monopolists, including Russia. In the end restoring well-functioning gas markets across the world would increase our well-being by reducing the diversion of resources into unproductive crash programs in energy. And that is a pretty big accomplishment.

Editor’s note: This article is the first of two posts on shale gas production and concerns the U.S. situation. The second will look at the potential impacts of shale gas production in Europe and China. While some have interpreted shale gas in terms of coal displacement in power generation, this new competition has profound (negative) implications for the viability of politically favored renewables in power generation.

Shale gas formations have been known for many years. But only in the 1990s did an understanding of hydraulic fracturing technology make production of gas from such formations feasible technically. And it was not until the middle of this decade, with U.S. domestic gas prices consistently above $10/mmbtu, that shale moved from an interesting future resource to a major current reserve.

The U.S. Department of Energy now estimates that recoverable shale gas resources in the U.S. total more than 550 tcf, with conversion of resources to reserves occurring at a rate of more than 1 tcf/year, above production. The production of shale gas and the increasingly economic production processes have reversed the historic decline of U.S. gas reserves, which stood at 293 tcf in 1968 and fell to 164 tcf in 1998. Dry gas reserve estimates for the U.S. as of December 31, 2007, stood at 237 tcf. Production has moved in a similar fashion (with a small lag), peaking in 1973 at 21.7 tcf, then falling to a plateau of about 17–19 tcf throughout the next three decades, until shale changed the domestic U.S. gas supply picture.

What Has the Shale Bonanza Meant for the U.S.?

Large-scale commercial production of natural gas from shales commenced only in the middle of this decade, becoming significant as a proportion of supply only in the last couple of years. In 2005, U.S. gas production stood at just over 18 tcf. In 2008, domestic production had risen to 20.6 tcf, reversing more than a decade of decline, and closing in on the 1973 peak production figure.

‘LNG to the rescue’: Conventional thinking in mid-decade was that only large-scale imports of liquefied natural gas (LNG) could meet the demands of the U.S. gas market. With prices tracking oil closely, the U.S. seemed the ideal target market for gas produced and liquefied in the Gulf, the European Arctic region, and off NW Australia. Along with rapidly rising demand from China, the producers of LNG could count on the two strongest economies in the world to support their gas exploitation plans. (And at attractive prices! Where else are you going to go for the gas?)

LNG is foiled by Mr. Market: LNG was considered so important for the U.S. energy supply picture that even the Maestro, Alan Greenspan, made specific mention of the importance of new LNG import and regasification capacity for the U.S. economy. Greenspan noted in 2003 that larger LNG import volumes would be likely to reduce the volatility of natural gas prices in the U.S. Before much new LNG import and regasification capacity could be built, however, natural gas prices soared, reaching $10/mmbtu at the wellhead in 2005 and again in 2008. LNG prices have proved less volatile, though generally they exceed domestic wellhead prices by more than 15%. In recent months, LNG has exacted a premium of more than 30% on domestic production. Increased domestic production of gas, much of it from shale, abetted by falling industrial demand in 2009, has tempered the price trends in the domestic U.S. market. Imports of LNG, rising through this decade, fell off in 2008 as growing domestic production opened up a significant pricing gap between LNG and domestic output. LNG comprised just above 1.5% of domestic gas supply in 2008, after rising as high as 3.5% earlier in the decade.

Reversal of Fortune: The U.S. DOE now projects that LNG imports will remain low throughout the next two decades, unlikely to account for even 5% of supply in the future. Shale formation gas production is expected to rise from 1.2 tcf in 2007 to more than 4–4.5 tcf by 2030, and will comprise more than 20% of total U.S. gas supply by then. Only California, aided by a group of politicians dedicated to fighting energy production and market forces, is likely to see increasing reliance on imported gas (through Mexico—none of those nasty regasification terminals for us!). Elsewhere along the U.S.-Mexico border the DOE expects increasing exports of U.S. gas to Mexico. In fact, the decline in Canadian conventional gas production raises the spectre of the U.S. becoming a net gas exporter by 2030 (table A13).

Hugo, Maybe Uncle Sam is Just Not That Into You

An article of unshakeable faith among many who look at energy security issues is that affirmative national policies are required to reduce U.S. dependence on the various global psychopaths bearing hydrocarbons. One has only to think of Hugo Chavez’s Venezuela, still a major U.S. supplier; the House of Saud, which now wants to be compensated if global oil demand falls (perhaps the U.S. Treasury can cut checks directly to al Qaeda, cutting out administrative costs and overhead in the Kingdom); and of course the Iranian poster boy for global energy supply nightmares, Ahmadinejad. A sense of unease comes naturally to most of us.

Added to the usual litany of supply-side nightmares—mostly about efforts to destroy the Abqaic processing and transfer station in Saudi Arabia and the vulnerability of crude oil and LNG shipping in the Strait of Hormuz—is the looming Chinese “threat” to world oil supplies. As the story is told, China, needing vast amounts of new energy to fuel its industrial machine, will go anywhere, pay any price, in the pursuit of energy supplies. Many of China’s recent forays have supported such thinking. With nary a concern about dictatorship, genocide, or rule of law, China has waded into the Sudan, Burma, and central Asia in search of oil and gas supplies.

Let me see if I have this right. In order to compete with China in locking up future hydrocarbon supplies, the U.S. has to be just as amoral, pay as much in bribes, and overlook the same transgressions for—the right to degrade our moral capital even more in the future? Surely, once there is even more intense competition between the U.S. and China for oil and gas resources, the price extracted by the beneficiaries of the oil curse will rise.

But if the U.S. is to be able to honor its history and ideals, then we had better take another look at our preferences for cutting deals with the world’s bad boys in order to keep the oil and gas flowing. Increased domestic supply financed by willing investors greatly improves our ability to resist the siren song of accommodation with the Hugos and Bashirs of the world, and teaches us a lesson, if we are willing to learn it.

U.S. Shale Gas: How to Do Things Right

The gas supply revolution provides a textbook example of how freeing up markets can help the U.S. pull back from the precipice of a series of uncomfortable and cynical foreign economic policy choices. Using our strengths in petroleum geology, engineering, and computer assisted simulation (a practical economic example of the military’s OODA loop), U.S. gas companies were able to see, assess, decide, and invest at a speed that has not only revolutionized domestic gas markets, but promises also to accomplish the same for the world.

With gas firmly ensconced as a reliable, economic source of clean energy for 100 years or more, the U.S. has a chance to develop the longer-term sources—clean coal, renewables, nuclear, oil shale, or other options—in a measured and efficient manner that does not hide the costs and benefits behind a screen of opaque governmental accounting methods. There is no pressing need for crash projects in renewables, which are, in any event, ineffective from the standpoint of both the energy supply and environmental concerns.

Still, there are those, especially in the U.S. political class, who see functioning energy markets and their supply-side results as a threat to state-directed energy programs. One has only to look at the nature of the increasing volume of noise on shale gas, domestic oil and gas drilling, offshore drilling, clean coal, shale oil and nuclear to understand that this debate is only partially about energy supply and the environment. The rest is about political power and the ability of those with that power to allocate the nation’s productive energy resources where they wish.