Chinese Closing 4 Remaining Coal Burners Near Beijing

Here’s the story from Bloomberg:

Beijing, where pollution averaged more than twice China’s national standard last year, will close the last of its four major coal-fired power plants next year.

The capital city will shutter China Huaneng Group Corp.’s 845-megawatt power plant in 2016, after last week closing plants owned by Guohua Electric Power Corp. and Beijing Energy Investment Holding Co., according to a statement Monday on the website of the city’s economic planning agency. A fourth major power plant, owned by China Datang Corp., was shut last year.

The facilities will be replaced by four gas-fired stations with capacity to supply 2.6 times more electricity than the coal plants.

The closures are part of a broader trend in China, which is the world’s biggest carbon emitter. Facing pressure at home and abroad, policy makers are racing to address the environmental damage seen as a byproduct of breakneck economic growth. Beijing plans to cut annual coal consumption by 13 million metric tons by 2017 from the 2012 level in a bid to slash the concentration of pollutants.

Shutting all the major coal power plants in the city, equivalent to reducing annual coal use by 9.2 million metric tons, is estimated to cut carbon emissions of about 30 million tons, said Tian Miao, a Beijing-based analyst at North Square Blue Oak Ltd., a London-based research company with a focus on China.

Coal emissions are killing more than half a million Chinese people a year.  The Chinese government now realizes it must do something, and do it fast, or there will be no more country to govern.

Also, don’t think for a minute that China is going coal free.  6 of the largest 10 coal-fired power plants in the world are in China, and they remain open.  The smallest of them has a capacity of 4600 MW.  The largest coal burner in the US is the Bowen Plant in Georgia, with a capacity of only 3499 MW.

But make no mistake, China is no longer relying on coal for new energy.  The Beijing plant closures are symptoms of rapidly accelerating trend.  This is more bad news for the US coal industry.

Get Ready for Life on the Bumpy Plateau

This post is a little side trip from the issues facing our electrical system.  Fossil fuel production has a direct bearing on how investment in electrical generation plays out, so questions of resource limits do have a direct bearing on understanding whether the people who run the US electrical system are making good decisions or bad decisions.

One of the main drivers of US electrical generation for the past ten years has been the glut of natural gas that has flooded US markets.  Gas has undercut coal as the preferred fuel for new electrical generation, leading to an increased dependence on natural gas in the US.

The US media has been touting the idea that analysts who claim world fossil fuel production is at or near peak production have been proved wrong by the recent “shale revolution.”  In fact, what we are seeing is exactly what analysts have predicted from the beginning: that as world production levels off, and prices rise, new drilling technologies will emerge that allow the production of poorer quality “plays,” but the production from these plays will be short lived and not nearly as productive as past discoveries.  The result will be big, short term floods of new production, followed by abrupt shortfalls leading to wide swings in price over shorter and shorter time periods.

None of the new production will contribute much to increasing overall world production.  Peak oil analysts refer to this period at peak production as “the bumpy plateau” before a steady decline trend takes hold.

In a recent discussion of the bumpy peak, energy expert Chris Nelder pointed out:

BP: So back in 2005, plenty of analysts were suggesting that the world would soon hit a ceiling in annual oil production. How has that panned out?

CN: The predictions weren’t monolithic. But what everyone agreed on was that at some point in the near future, maybe five or 10 or 15 years away, the rate of oil production would stop growing. Some said we’d hit an absolute peak in a specific year. Others said we’d reach a “bumpy plateau” that might be five or 10 years long. But everyone agreed that sometime after 2005, within 10 or 15 years, global oil production would stop growing.

CN: Not necessarily. In 2005, we reached 73 million barrels per day. Then, to increase production beyond that, the world had to double spending on oil production. In 2012, we’re now spending $600 billion. The price of oil has tripled. And yet, for all that additional expenditure, we’ve only raised production 3 percent to 75 million barrels per day [since 2005].

The increasing uncertainty about fossil fuel production, particularly oil and gas, are further detailed in a just released study by the Post Carbon Institute called Drilling Deeper: A Reality Check On U.S. Government Forecasts For a Lasting Tight Oil & Shale Gas Boom by David Hughes.  Here are the key findings of this report taken from the executive summary:

The seven tight oil plays and seven shale gas plays analyzed in this report account for 82% of projected tight oil production and 88% of projected shale gas production through 2040 in the EIA’s Annual Energy Outlook 2014 reference case forecast. A detailed analysis of well production data from these plays resulted in these key findings:
1) Tight oil production from major plays will peak before 2020. Barring major new discoveries on the scale of the Bakken or Eagle Ford, production will be far below EIA’s forecast by 2040.
a) Tight oil production from the two top plays, the Bakken and Eagle Ford, will underperform EIA’s reference case oil recovery by 28% from 2013 to 2040, and more of this production will be front-loaded than the EIA estimates.
b) By 2040, production rates from the Bakken and Eagle Ford will be less than a tenth of that projected by EIA.
c) Tight oil production forecast by the EIA from plays other than the Bakken and Eagle Ford is in most cases highly optimistic and unlikely to be realized at the rates projected.
2) Shale gas production from the top seven plays will likely peak before 2020. Barring major new discoveries on the scale of the Marcellus, production will be far below EIA’s forecast by 2040.
a) Shale gas production from the top seven plays will underperform EIA’s reference case forecast by 39% from 2014 to 2040 period, and more of this production will be front-loaded than EIA estimates.
b) By 2040, production rates from these plays will be about one-third that of the EIA forecast.
c) Production from shale gas plays other than the top seven will need to be four times that estimated by EIA in order to meet its reference case forecast.
3) Over the short term, U.S. production of both shale gas and tight oil is projected to be robust—but a thorough review of the production data indicate that this will be unsustainable in the longer term.
These findings have clear implications for current domestic and foreign policy discussions, which generally assume decades of U.S. oil and gas abundance.  Other factors that could limit production are public pushback as a result of health and environmental concerns, and capital constraints that could result from lower oil or gas prices or higher interest rates.  As such factors have not been included in this analysis, the findings of this report represent a “best case” scenario for market, capital, and political conditions.

The prospect of more volatile swings in fuel prices poses significant problems for long term investment in projects like big electric generating plants or natural gas pipelines.  What investors would be willing to invest in a 50 year project when price instability might severely impair the ability of the project to pay for itself over such a long term?

The competition among fuels also illustrates what may really be behind the coal industry’s current push to fight regulation of coal burning in US electric generating plants.  Right now, coal is the big loser in the energy price war.  Given Hughes’ analysis, however, we may see rapid rises in natural gas prices as shale production drops rapidly.  If the US coal industry can block further expansion and enforcement of the Clean Air Act, the industry will be poised for a big boom as gas prices rise and coal becomes more competitive.

Sarah Tincher, the energy reporter at The State Journal, has a good story on the interplay of these forces in the coal industry.  As Ms. Tincher’s story points out, gas prices would have to rise pretty high for Central Appalachian steam coal to become competitive, because the resource in the region is now so degraded and costly to mine, but western and midwestern coal would be much more likely to rebound.

The volatility problem would also be a limiting factor to any coal rebound in electrical generation, however.  Right now, there are almost no new coal-fired power plants being built in the US.  Because of the current gas glut, many high cost, obsolete coal burners have been shut down.  In order for power companies to take advantage of coal’s possible new competitiveness, they would have to make new 50 year investments in building new plants.  Would they do that if they faced the uncertainty of wild swings in coal’s competitiveness?

Even if a fossil fuel gains a price advantage over another fuel, industry may not be able to use that advantage effectively, because it cannot make needed long term investments in an increasingly unstable market environment.  So, all environmental considerations aside, renewable power becomes increasingly attractive, because renewable power needs no fuel.  Once the long term investment is made to build generation, there is no fuel price uncertainty for the future.  Renewable power investments can also be made in very small units, unlike building a coal-fired power plant, so each new investment is inherently less risky.

We could be on the bumpy plateau for twenty years or fifty years, before fossil fuel production establishes its long term decline.  Everyone will have to adjust to wild swings of fuel prices, investment decisions and our economy.  Hold onto your hats.

Once Again, the Problems with Fossil Power – Transmission, Centralized Generation, Fuel Risk

There is a very interesting article this morning in the New York Times about the natural gas crisis in New England.  The story is by our old friend Matt Wald, who appears, once again, to be pushing for new transmission.  This time it’s gas transmission.

Down here in WV, we are used to the constant drumbeat of corporate propaganda about the New Age of natural gas plenty.  In New England, they are running short of gas:

Electricity prices in New England have been four to eight times higher than normal in the last few weeks, as the region’s extreme reliance on natural gas for power supplies has collided with a surge in demand for heating.

There is a fundamental difference between coal and natural gas.  Coal is no longer used as a primary heating fuel, while gas is the most efficient fossil fuel for building heat.  Electricity demand faces two peak periods every year, which vary by location.  One peak is in the summer, especially in warm climates, when there is a lot of demand for air conditioning.  The other peak is in the winter when heating draws power, particularly in colder northern areas.

In cold climates, during winter electricity peaks, direct use of gas for heating also peaks.  If there is not enough pipeline infrastructure in a region to handle the massive surge of gas needed to fuel both the electricity peak and the gas heating peak, natural gas supply is sucked dry, causing skyrocketing prices.

James G. Daly, vice president for energy supply at Northeast Utilities, a company that, through its subsidiaries, provides electricity to homes and businesses in Connecticut, Massachusetts and New Hampshire, said: “There is concern we don’t have enough capacity to supply heating and electricity generation.”

Northeast and many other companies are temporarily insulated from the spot market because they sign long-term contracts for electricity supply. But Northeast’s energy charges next year could be 10 percent higher than they are now, Mr. Daly said, because the companies that sell power on a long-term basis will charge more to absorb the risk of short-term spikes in prices.

In his usual style, Mr. Wald responds to this situation by wistfully yearning for the good old days of obsolete coal-fired power plants and heavily subsidized nuke plants that are still storing their dangerous radioactive waste on site, near major population centers.  But here is his big solution:

But the biggest problem may be the inadequacy of existing pipelines. On Feb. 7, ISO New England told the Federal Energy Regulatory Commission that it was concerned about “increasing reliance on natural gas-fueled generators at times when there is an increasingly tight availability of pipeline capacity to deliver natural gas from the south and west to New England.”

Yup, that’s right.  Matt Wald wants more transmission capacity.  Who could have seen that coming?  This time he wants it for gas.

He points to the real problem at the end of his article, but he never realizes what the facts are telling him.  Here are the hints that he never picks up on:

During the storm last week, with transmission lines being knocked out by snow and high winds, ISO asked some gas-fired generators to start running in the middle of the night…

And

About 30 percent of the generators in the region burn coal and oil, Dr. Chadalavada said, but they produce less than 1 percent of the energy because they run so seldom. Some can take 24 hours to return to service.

That’s right.  The problem isn’t with using natural gas or coal or with not enough pipelines.  The problem is that we are dependent on long distance dispatch of both electricity and gas.  Both are dependent on fragile infrastructure and unresponsive generation technologies, as well as the big one – fuel uncertainty.  While Mr. Wald does a very good job of describing New England’s current problems, he fails to go one step further, as always, to point out what is really going on.

It is ironic in the extreme that New England, off its Atlantic Coast, has the best wind power resources in the US, but, thanks to David Koch, Mitt Romney and the Kennedy family, New England has 0, yes that is ZERO, offshore wind generation capacity, which is (1) close to coastal population centers and (2) requires no fuel.

But Mr. Wald thinks that New England’s big infrastructure problem is that they don’t have enough natural gas pipelines.  The problem with this “solution” is that investment in new transmission capacity, whether it is pipelines or power lines, is outrageously expensive, if it is designed to deal only with peak capacity needs.  Rate payers pay for massive new capacity, which then sits underused for all but a few days during the year.

Once again, poor old Matt Wald misses the real story here.  His whole article is an eloquent argument for decentralized, largely renewable, power generation and resilient microgrids, but he misses this point entirely.

More on Dispatch — Huge FirstEnergy Coal Plant Goes Off Base Load Status

Here is a perfect example of the trends identified by the EIA in my earlier post.  FirstEnergy’s huge Sammis plant in Jefferson County, OH near Steubenville is being scaled back to a “dispatch-only-when-needed footing.”  This is a 2233 megawatt plant in which FirstEnergy recently invested $1.8 billion in pollution control.  If power companies are idling coal plants like Sammis, there is a real shift going on.

The FirstEnergy press release (from which the reporter obviously got the entire story) apparently focused on low gas prices, but note the other reference to low electricity prices.  Electricity prices are low because the long term trend for electricity demand in PJM is downward.  This trend will not change if natural gas prices rise.

FirstEnergy now operates in a newly deregulated Ohio electricity market.  The company is being forced to by less expensive gas fired power on the open market, while it idles its own coal fired plants.  Meanwhile, in WV’s regulated and coal-controlled electricity market, electric rates continued to rise because they are tied entirely to more expensive coal fuel and coal burning technologies.

 

Good Explanation of How RTOs Prioritize Dispatch from Generators

Most of us don’t understand where our electricity comes from.  We think somehow our houses and businesses are connected directly to power plants that send us our electricity.

In fact, the situation is very different.  Electricity is “dispatched” by regional transmission organizations from a wide range of generating plants depending on the minute to minute cost of the power produced by those plants.  This is the principle of economic dispatch designed to insure that the lowest cost electricity is always being sent to customers.

In debates and discussions concerning renewable power, opponents of wind power, both the coal and nuclear industries and so-called environmentalists, claim that wind power is too expensive and is never used by electric companies.  In fact, because wind power has no fuel costs, it is almost always dispatched first, when it is available.

Here is an excellent description of the impact of the cost of generation on RTO dispatch policies from the DoE’s EIA.  The article also includes this very helpful graph that illustrates how cost and dispatch interact at different levels of demand.

https://i1.wp.com/www.eia.gov/todayinenergy/images/2012.08.17/DispatchCurve.png

Here is the EIA’s discussion of current dispatch trends:

The exact order of dispatch varies across the United States, depending on such factors as fuel costs, availability of renewable energy resources, and the characteristics of local generating units. The type of generators with the lowest variable costs are nuclear, hydroelectric, and renewable power (wind and solar). For economic and technical reasons, nuclear plants in the United States are almost invariably operated as baseload units at maximum output. While wind and solar plants have very low operating costs, their availability is limited by the availability of the resource (i.e., whether the wind is blowing or the sun is shining). Some electric power systems dispatch these variable resources, others do not, and wind generators are sometimes curtailed to keep electric supply in balance with demand.

Although hydroelectric plants also have very low variable costs, their dispatch patterns are influenced by many factors, including: current and projected reservoir levels, environmental factors, timing output to maximize revenues, and the need in some locations to balance variable wind and solar output. For these reasons hydroelectric dispatch patterns can be complex.

The variable cost of generating electricity from fossil-fueled units is primarily a function of the fuel price and the efficiency of the plant’s conversion of the fuel into electricity. Historically coal plants have operated as baseload units while natural gas-fired plants in many regional power markets have have met intermediate and peak load needs. This was a function of the low cost of coal fuel compared to natural gas. This fuel cost advantage was sufficient to overcome the efficiency advantage of the new vintage of gas-fired generators built beginning in the 1990s. However, more recently gas prices have declined, and these efficient gas-burning combined cycle plants have begun to displace coal as baseload generation.

Peaking generators typically have the highest variable operating costs, appearing on the far right of the supply curve, and are dispatched during the hours when demand for electricity is highest. Peaking unit technology includes diesel generators and, most commonly, combustion turbines (CTs) fueled by natural gas. Combustion turbines have been used for many years, and older units are inefficient. However, the newest units have greatly improved efficiency, to the point that, with the advantage of low gas prices, the newer CTs have begun to back-out some coal generation. This dispatch pattern has only been seen in recent years.

Note that even in the US, highly efficient combined cycle natural gas plants are now beginning to displace coal plants for base load power.  Also note that wind turbines are shut down by RTOs not because they are too expensive, but because nuclear base load plants can’t be shut down to allow for less expensive wind-generated power.

From this account of dispatch practices, you can also see why AEP and other coal-fired power companies are closing their high cost, obsolete coal plants.  It’s not because of the EPA.  These old, high operating cost plants are now being displaced by gas-fired power as base load.  These obsolete plants are only able to sell power profitably when demand is high enough to raise prices.  Because coal plants’ steam turbines take a long time to ramp up and shut down, it doesn’t make economic sense to only run them a few days a week or for an hour a day, essentially the way gas “peaker” plants are run.

Thanks to Grounded for highlighting these EIA features.

Wall Street Turning Away from Coal

If there is no investment today, there won’t be any coal-fired power plants tomorrow.  That is the topic of this story in today’s Washington Post.

The report documents the continuing decline of coal as a fuel for electrical generation.  Wall Street bankers have stopped investing in new coal fired power plants.

“Coal is a dead man walkin’,” says Kevin Parker, global head of asset management and a member of the executive committee at Deutsche Bank. “Banks won’t finance them. Insurance companies won’t insure them. The EPA is coming after them. . . . And the economics to make it clean don’t work.”

Coal’s formerly dominant position is steadily being eroded by natural gas.

In 2002, there were plans to install 36,000 megawatts of new coal-fired power by 2007. Only one-eighth of that was completed.

Deutsche Bank predicts coal’s share of electric power generation will tumble further, from 47 percent in 2009 to 34 percent in 2020 and 22 percent in 2030.

It put it this way in its report: “Based on today’s energy fundamentals, the rational economic decision is to shutter inefficient coal plants and replace them with natural gas combined-cycle power plants.”

This decline of coal is not necessarily good news for opponents of PATH.  AEP/Allegheny can’t build new coal plants, so they have to make their existing plants as profitable as possible.  That means getting access to the east coast by using Project Mountaineer and the PJM “reliability” smokescreen.

The decline of coal has hit US coal miners hardest.  As coal demand falls, coal companies also try to keep their profits up by cutting costs.  In a coal mine, that means miners die.  2010 was the deadliest year in US coal mines in almost two decades.  Of the 48 US miners who died, 35 were West Virginians.  Twenty nine of those miners died in Massey’s Upper Big Branch mine, but most of the other nine miners, as Ken Ward always reminds us, died alone and in the dark.