The Transformer – A bridge to somewhere? Natural gas, LNG and our clean energy future

A bridge to somewhere?

Natural gas, LNG and our clean energy future

Vol. 6, No. 3

Lifecycle carbon emissions, supply and price volatility must be considered when evaluating the role of natural gas turbines in cutting our reliance on coal-fired power plants.


More than 10 years ago, the Oregon Public Utility Commission coined the term “bridging strategy” to describe a way to facilitate utilities’ necessary evolution from coal to renewables. The theory was that the renewable industry wasn’t big enough or technically advanced enough to compete with coal and wouldn’t be for years, so utilities should consider natural gas a “bridge” resource during the transition.

This bridge, convention wisdom says, is built upon five assumptions:

  • Generating electricity with natural gas-fired combustion turbines (CTs) produces less than half the greenhouse gas emissions of coal-fueled generation, a third less nitrogen oxides and almost no other pollutants.
  • Natural gas is relatively plentiful.
  • Compared to capital-intensive coal or nuclear plants, combustion turbines can be built fairly cheaply and quickly.
  • Gas-fired CTs can be ramped up and down to integrate variable wind power, unlike inflexible coal and nuclear plants.
  • CTs’ small size engenders relatively little public opposition, so they’re much easier to site near loads and thus require little new transmission.

These assumptions have led more and more utilities to substitute gas-fired CTs for coal in their resource plans while rapidly expanding their use of renewables and efficiency.  But are the assumptions correct?  The new rush to gas is raising serious questions about domestic and international supply, price and price volatility, and lifecycle carbon emissions.

This edition of The Transformer addresses those questions and considers the controversy surrounding liquefied natural gas (LNG).

Inevitable booms and busts

Natural gas prices have been on a decade-long roller coaster ride. Each price spike and plummet has its own story, but all reflect the fundamental fact that gas is a deregulated commodity whose price is determined by supply and demand. Since neither the supply of nor the demand for natural gas can quickly react to changing conditions, gas prices inevitably bow to boom-and-bust cycles.

For example, it takes six months to a year to tap new wells in response to rising demand to heat larger houses, fuel gas fireplaces, etc. So as demand increases, new supply lags, causing prices to spike.  Higher prices slow economic activity.  Customers cut back or switch to electric heat or to diesel fuel for industrial uses just as gas drilling is ramping up. Eventually supply outpaces demand and the price crashes. Low prices then draw people and businesses back to gas while, of course, gas drillers ramp down their drilling. Another cycle ensues.

Just 10 years ago, natural gas (methane) cost about $2 per million British thermal units (mmBtu).  In the summer of 2008, in what many analysts considered a speculative “bubble,” the price spiked to more than $16 per mmBtu before crashing with other commodities to the current level of about $4/mmBtu.

It takes a little less than 10 Btu to generate a kilowatt-hour of electricity in a combustion turbine, so a good rule of thumb is that $1 per million Btu represents about 1 cent per kilowatt-hour of electricity.  Reflecting that rule, the wholesale price of electricity rose from 2 cents per kWh a decade ago to 16 cents briefly last summer, and now (December 2009) stands at about 4 cents per kWh.

Replacing price-stable coal with natural gas generation makes consumers, utilities and their regulators nervous since it requires more aggressive and vigilant management of prices and rate effects.

Home and abroad

Lack of import or export capability makes North American natural gas prices relatively independent from international prices.   For the most part, regional supply and demand set our prices.

The international natural gas market price, on the other hand, is set mainly by the cost of oil. A million Btu of gas has about 7.5 times the energy content of a barrel of oil, and since many large industrial users can switch between the two, the relative fuel prices traditionally reflect the energy ratio. When the price of one fuel rises too high compared with the other, these users switch causing demand for the higher-priced fuel to fall and restoring the 7.5:1 price ratio.  As the much larger and more important commodity, oil’s price ultimately controls that of natural gas.

The price of oil is determined by many factors, most significantly a razor-thin balance of supply and demand. Given the general expectation of diminishing supplies of inexpensive oil – the “peak oil” phenomenon – the price should stay fairly high.

Oil prices have declined significantly from last year’s historic highs, but most experts expect them to rise much higher than today’s $70-80 or so per barrel. The availability of alternatives – most importantly electricity for transportation, oil’s No. 1 use – should keep oil prices below about $150 over the long term. As per-barrel prices again rise to that range, natural gas prices should approach $14-$18 per million Btu for gas sold in international markets.

Until quite recently, the international oil price had little effect on North American natural gas prices. Gas was used primarily for heating and electricity generation and oil primarily for transportation, with little overlap.

That’s changing. In the last few years, international oil prices have started to affect the North American natural gas market. For example, high international oil prices have made oil extraction from Alberta’s tar sands profitable. Liquefying the tar requires vast amounts of steam produced by burning natural gas, thus further hiking gas demand and price.

North American gas prices remain somewhat insulated from oil prices, but that won’t keep our gas costs from rising.  In Canada, which traditionally has provided most of the U.S. Northwest’s natural gas, producers are seeking new gas wells farther north.  Drilling on the Rocky Mountain Front has dramatically increased, as has interest in bringing gas down from Alaska.  Tapping these sources will require huge new investments in pipelines, so one would expect gas prices to keep rising.

Enter LNG

With prices uncertain and long-term continental supply in question, utilities and merchant developers are considering a controversial alternative: imported liquefied natural gas. LNG is natural gas that has been compressed and liquefied, transported by tankers, then re-gasified and fed into the regional pipeline network. LNG meant for West Coast delivery comes mainly from Indonesia, Qatar, Russia and Australia.

The gas itself is usually a simple byproduct of oil drilling and thus has a low cost at the wellhead.  Processing and shipping it to the United States, however, costs a lot of money and consumes a lot of energy. , As discussed above, the cost of the gas has little connection to its price.  The price of LNG, an international commodity, is determined as much by the price of oil (at that 7.5:1 ratio) as by its own extraction and delivery costs. Sellers get whatever the market will bear up to the Btu-equivalent price of oil. In fact, most long-term LNG contract prices are indexed to oil prices rather than being set at specific amounts.

LNG prices are linked to the price of oil, but North American gas prices are set mainly by continental supply and demand. Thus LNG can compete with natural gas here only if domestic gas prices rise (or international oil prices drop—which is unlikely in the long term) significantly.  But is that likely?

A few years ago, many investors smelled a sure winner in multi-billion-dollar North American LNG terminals.  Domestic demand for natural gas was rising due to load growth and a move away from coal-fueled power production. Meanwhile, Canadian supplies were diminishing and the tar sands were claiming a growing share of the resource. These developments led to confident forecasts of North American natural gas prices rising up to and beyond the international price of gas.

Developers proposed a slew of new LNG import sites, arousing significant local opposition.  The industry argued that the energy need was too great to leave siting decisions to local jurisdictions.  It lobbied Congress to pass a law giving the Federal Energy Regulatory Commission authority to override local governments on LNG terminal siting.

But the rise in North American natural gas prices has brought a competing player onto the field.

The shale game

Geologists have long known about vast quantities (perhaps a 100-year supply) of hard-to-reach natural gas trapped in so-called “tight shale” formations in the Rockies, Texas and elsewhere. Rising gas prices drove development of new technology that involves drilling down and then sideways through the gas-filled layers and pumping in a highly compressed – and highly toxic — sand and fluid mixture to fracture the layers and release the gas.  The sand keeps the layers separated so the gas continues to flow.

Shale drilling comes at an environmental cost – principally the contamination of both surface and groundwater. Fracturing the rock layers releases the natural gas at high pressure.  Both the fracturing fluids, including poisonous chemicals such as benzene, and the gas can blow back into the drill hole and/or migrate through the rocks to the water table. Methane has leaked through drinking water into homes and wellhead buildings, causing several spectacular explosions as production has peaked.

The industry successfully lobbied to exempt shale drilling from the Clean Water Act a few years ago, arguing that state laws were adequate, that problems had been found in just a small fraction of the thousands of wells now in operation and that some methane contamination is natural or, at worst, the result of faulty drilling methods. The industry continues to oppose federal regulation while simultaneously denying that any problems exist and claiming that proper drilling methods can fix any problems that do.

In the absence of much regulation, tight shale drilling has boomed, creating a large surplus of continental natural gas. The surplus, combined with the economic slowdown, has for the moment slowed drilling. Tight shale extraction becomes economic when gas prices reach $6-8 per mmBtu. Higher prices would significantly increase extraction of the ample resource, eventually pushing the price back down. Thus most economists believe gas prices will average around $6 to $8, but remain subject to boom-and-bust swings.

Plummeting oil prices earlier this year made LNG temporarily competitive with domestic natural gas.  The few operating North American terminals received some LNG shipments after a period in which imports had come to a halt. But few investors will bet billions on prices staying low, so construction of new LNG import terminals is unlikely at this time.

In fact, the shale gas boom has some LNG firms talking about building export rather than import facilities. One British Columbia developer is moving ahead with plans to turn a previously permitted import facility into an export terminal.  Should such conversions actually occur on a large enough scale, North American gas prices would start to mirror international prices, causing them to skyrocket when oil prices increase.

The question of clean

Given the price volatility, price is not the main reason utilities turn to natural gas or LNG.  The big plus for gas is its cleanliness compared to coal. And to reduce global warming pollution in the energy sector, we must focus almost entirely on phasing out coal. Coal-fired power generation is responsible for about a third of U.S. greenhouse gas emissions, more than any source other than transportation. Coal provides less than a quarter of the electricity consumed in the hydro-based Northwest but more than 85% of the regional grid’s climate pollution.

In a May 2007 study, Pace Global Energy Services (, an international consulting firm that helps corporations “determine the impacts of a carbon-constrained world on their business,” investigated the lifecycle carbon footprint of electricity generated from North American natural gas, LNG and coal for Northwest use.

This study, using Northwest plant efficiency averages and the Btu content of Powder River Basin coal, shows that generating 1 megawatt-hour of electricity from coal creates up to 2,900 pounds of carbon dioxide (CO2 — technically CO2-equivalent, abbreviated CO2-e). Generating the same megawatt-hour from natural gas produces 1,012 pounds of CO2. But those numbers don’t paint the whole picture.  To compare emissions fairly, we must include those produced by fuel extraction, production and transportation, in addition to power-producing combustion.

Using natural gas for electricity creates greenhouse gas emissions at numerous points. North American gas must be compressed at the well, sent by pipeline to a processing plant for cleaning and de-humidifying, then transported again for storage and distribution. “Fugitive emissions,” or leaks, are fairly small, but their impact is great since natural gas is methane, which has about 23 times the greenhouse effect of CO2.   Processing and compressing use energy; in fact, compressor stations along the pipeline use so much energy that many operators are starting to capture the compressors’ waste heat to generate electricity.

The Pace study adds all these emissions to those from burning North American gas in a combustion turbine to arrive at a total of 1,087 pounds of CO2-e per MWh.

LNG brings significant additional points of pollution, however.  The gas must be compressed to a liquid, shipped by tanker and then re-gasified.  These steps require lots of energy, so the emissions from well to wall outlet total 1,360 pounds per MWh — about 25% more than North American gas.

Then Pace did the calculation for coal. Coal power emissions come from:

  • Methane released during coal mining
  • Energy used in mining, handling and crushing the coal
  • Energy used in transporting the coal by rail to the generating plant.

These emissions, in addition to the stack emissions from the generating plant, total 2,949 pounds per MWh.  (It should be noted that the Pace study does not account for environmental degradation from mining, drilling or pipeline construction, or for the emissions from the construction of the trucks, pipes, ships and other equipment used during the generation lifecycle.

Results of the Pace study are summarized below:

Total greenhouse gas emissions
(pounds of CO2-equivalent per MWh)

North American
natural gas


Powder River Basin coal

















Lifecycle total




Percentage compared to North American natural gas



CO2-e cost per kWh

at $40/ton



Clearly, coal is incredibly dirty. Even with expensive scrubbers, coal plants emit mercury, particulates and sulfur and nitrogen oxides (SOx and NOx) that contribute to acid rain, haze and health problems, not to mention climate-changing CO2. Putting a value of $40/ton on CO2 emissions — a typical number resulting from of a modest cap-and-trade mechanism — more than doubles the current wholesale price of coal-fired electricity.

Natural gas is much cleaner than coal, with almost no SOx, a third of the NOx, and fewer other pollutants, and half to a third of the carbon dioxide.  For example, the Power and Conservation Council analyzed a scenario that shuts down all the coal plants serving the region by 2020 and replaces their electricity with gas-fired power.  This scenario reduces regional electric utility emissions by 75%. Still, a $40-per-ton CO2 charge adds almost 2 cents per kWh to the wholesale cost of electricity produced from North American natural gas. Generation from LNG adds nearly 2½ cents per kWh to the electricity’s wholesale cost.

Of course, energy efficiency and new renewable sources produce little or no lifecycle carbon emissions and thus are subject to no future CO2 penalties. So to the extent that we can replace fossil-fueled power with clean energy, we can reduce climate pollution and costs.

Moving ahead

We must shut down existing coal plants as quickly as possible to staunch global warming. The Coalition’s Bright Future study shows that the NW can phase out most of its coal-fired generation over a long time horizon with energy efficiency and renewable resources.  The Power Council’s draft 6th Plan shows that in order to retire the same amount of coal generation on a faster time schedule would require new gas-fired generation.

Can we replace the dirty plants’ power with more energy efficiency and new clean renewables, along with existing gas plants? Can we get more capacity out of the existing gas plants?  Or must we “bridge” the gap by building new natural-gas generating facilities that still emit (admittedly fewer) climate-changing pollutants and subject consumers to recurring boom-and-bust price cycles?  And if we turn to more gas, we will need to acknowledge that gas supplies will increasingly come from shale gas and LNG.  Can we overcome the environmental and economic challenges of producing shale gas or importing LNG?

These questions must be addressed and answered as we move toward a brighter, cleaner energy future. We welcome your contributions to this critical discussion.

What do you think?

We are interested in your reactions to these articles. We will print as many responses as possible in future editions of The Transformer.

Please email comments to

The Transformer is a regular electronic publication of the NW Energy Coalition, distributed free of charge, that offers thoughtful discussion and analysis of trends, issues and controversies affecting Northwest energy policy. Subscribe online or contact
The NW Energy Coalition is an alliance of more than 110 environmental, civic and human service organizations, progressive utilities and businesses in Oregon, Washington, Idaho, Montana, Alaska and British Columbia. We promote development of renewable energy and energy conservation, consumer protection, low-income energy assistance, and fish and wildlife restoration on the Columbia and Snake rivers.