Category Archives: Energy

NRDC Blasts Dominion’s $13 Billion Cost Projection

With least cost planning, says the NRDC, Virginia would continue to sufficiently reduce carbon emissions, in absence of Dominion’s IRP proposal.

With least cost planning, says the NRDC, Virginia would continue to sufficiently reduce carbon emissions, in absence of Dominion’s IRP proposal.

by James A. Bacon

The 15-year planning document filed by Dominion Virginia Power last week vastly overstates the cost of complying with the Clean Power Plan and is chock-full of errors, flaws and misjudgments, charged Walton Shepherd, staff attorney for the National Resources Defense Council (NRDC) and a member of a committee of stakeholders advising the McAuliffe administration on how to comply with the plan, should it meet federal court approval.

“Dominion’s IRP … outlines a gargantuan, $13 billion energy plan to reduce total carbon pollution that asks its customers to pay for a Ferrari, when it already has a finely tuned car that can safely — and more affordably — get everyone to the store and back in time for dinner,” wrote Shepherd.

In a blog NRDC post yesterday, Shepherd cited three major flaws in Dominion’s analysis.

  1. Dominion’s $12.8 billion dollar building plan assumes that it will have to replace electricity generated by every single one of its coal-fired plants. That’s not true, he said. As a result of previous initiatives undertaken before the announcement of the Clean Power Plan, Virginia “has already achieved so much of its compliance obligation that it would likely make the carbon reductions required by the Clean Power Plan even in absence of the federal regulations.”
  2. Dominion disregards the existence of the interstate electricity grid — the company is part of the PJM regional transmission organization — which allows it to tap into wholesale electricity markets. “That national grid, which of course includes all of Virginia in its continent-wide footprint, is precisely why Dominion doesn’t need to build new plants: transporting cheaper and cleaner electricity from elsewhere was the entire point of building out our vast and sophisticated transmission network.”
  3. Dominion’s plan overlooks the obligation by Virginia regulators to find the least-cost measure to meet customer needs. “Robust analysis of the CPP shows the compliance costs for the entire region (of VA, WV, PA, OH, and NJ) to reduce carbon pollution from existing and future power plants could be less than one-fifth of Dominion’s cost of $13 billion, which is a price tag for Virginians to pay alone.”

Bacon’s bottom line. The first point requires some explanation for readers not intimately familiar with this debate: That $13 billion price tag is Dominion’s estimate for what it says is the most expensive of the four Clean Power Plan compliance strategies (so-called Plan E) on the table — the plan preferred by Shepherd and the NRDC. It would impose a mass-based cap on carbon dioxide emissions from Virginia’s fossil fuel-fired generating fleet, including existing and new facilities — 27.43 million short tons of CO2 in 2030 and beyond.

To achieve that goal, Dominion maintains that it would have to go beyond the currently planned shutdown of oil-fired Unit 3 at Yorktown Power Station, coal-fired Units 3 and 4 at Chesterfield Power Station, and both coal-fired units at Mecklenburg Power Station. Dominion’s econometric modeling suggests that Plan E would require the shut-down of Units 5 and 6 at Chesterfield, both units at Clover Power Station by 2022, and the Virginia Hybrid Energy Center by 2029.

Shepherd is contesting that assertion. He is saying that simply following existing policy, which shuts down coal-fired units to meet the toxic-emission standards issued earlier this decade, got Virginia below the mass-based level at temporarily in 2012, and that it would take only modest effort to keep it below that level through 2030. (See the chart above.) This appears to be a fundamental disagreement in analysis with Dominion.

On the second point: Dominion’s 2016 IRP does indeed glide over discussion of purchasing power on the wholesale markets. One of the advantages to participating in a regional electric grid is that it is easier to balance electric-generating sources, especially variable sources like wind and solar, over a larger geographic area. PJM has said that the system should be able to accommodate as much as 30% renewable power without jeopardizing grid reliability.

However, Shepherd’s understanding of how the PJM grid works differs from mine. It is not a vehicle that Dominion can tap to import vast supplies of renewable energy. Some renewable energy, yes, but not limitless amounts. First, there are transmission constraints. There is a limited number of transmission lines with a finite amount of capacity, which cannot be exceeded without incurring significant congestion charges and creating reliability issues. Second, Dominion cannot simply be an electricity taker. It has to be able to feed power into the regional grid as well in order to help maintain the regional balance. Perhaps Dominion could purchase more electricity off the regional grid, but it’s not clear how much more.

On the third point: Dominion says compliance will cost $12.8 billion, NRDC says it will cost one-fifth that amount for Virginia and nearby states. Dominion has its econometric model; NRDC has its own econometric model. Without knowing the inputs and constructions of each model, it is impossible for disinterested citizens to know which is a more accurate representation of reality.

Why Dominion Is Cautious about Solar

solar_panelsJames A. Bacon

Solar energy may account for a barely perceptible sliver of Dominion Virginia Power’s electric generating portfolio today, but the power company sees an increasing role for it in the future.

Even under its “low cost” scenario, Dominion foresees installing 1,000 megawatts of photovoltaic (PV) solar energy by 2041. Under a variety of other scenarios designed to meet the goals of the Clean Power Plan, which may or may not pass U.S. Supreme Court muster by 2041, solar could comprise between 2,100 megawatts and 8,000 megawatts of capacity. That compares to about 24,000 megawatts of current capacity across the utility’s power generation fleet.

Those numbers come from Dominion’s 2016 Integrated Resources Plan, a planning document filed last week in which the company lays out its expectations for electricity demand and its strategy for meeting that demand.

While the company expects a bigger role for sun-powered electric generation, the IRP raises concerns about the difficulty of integrating large amounts of solar, an inherently intermittent source of electric power, into a system that requires stability and predictability.

One commonly heard critique of solar is that it delivers electricity when the sun is shining, not when it is needed. (It is not “dispatchable.”) Therefore, the power company must either maintain backup power capacity or purchase electricity from elsewhere on the regional grid, both of which can be expensive. The 2016 IRP goes into great length elaborating upon a different problem: the difficulty of integrating large volumes of solar-generated electricity into the transmission and distribution grid.

In effect, says Dominion, the move to solar represents a paradigm shift in how electricity is generated and distributed. States the IRP:

All levels of the existing electric infrastructure, standards and operating protocols were originally designed for a dispatchable generation fleet (based on the market price as well as the topological condition of the electric network). This paradigm ensures system stability through control of frequency and voltage. PV generation systems, in contrast, only produce electricity when the sun is shining; therefore, energy output is variable and cannot be dispatched.

Conventional generating facilities are utility-scale, while solar panels installed by homeowners, businesses and public institutions bypasses the transmission grid and ties into local distribution circuits.

Therefore, the electric grid is evolving from a network where power flows from centralized generators through the transmission network and then to distribution systems down to the retail customer, into a network with generators of many sizes introduced into every level of the grid. The overall result is that traditional assumptions about the direction of power flows are no longer valid.

Meter readings from the Virginia Solar Pathways Project. (Click for larger image)

Meter readings from the Virginia Solar Pathways Project. (Click for larger image)

Fluctuations in electric power output cause variable power injections and losses on the grid, impacting frequency and voltage, which the industry must control within tight parameters. That’s not a problem when PV penetration is low, states the IRP, but it can be a problem when PV constitutes a larger percentage of power production. “On a multistate level, it is possible that the resulting sudden power loss from disconnection of distributed PV generation could be sufficient to destabilize the system frequency of the entire Eastern Interconnection.”

There are fixes for these problems — but they cost money. Static synchronous compensators (STATCOMs) can help prevent “voltage flicker” from solar power. Similarly, PV inverters, which invert the DC output of a solar PV facility into AC, continuously monitor the grid for voltage and frequency levels. High resolution meters, such as synchrophasors and digital fault recorder devices placed at the point of interconnection, support high-speed tripping to address power quality concerns.

So, how expensive would it be to upgrade the electric grid to accommodate a significantly higher contribution of solar power? The IRP alludes to a 2015 filing by Southern California Edison, estimating capital expenditures in the range of $1.4 billion to $2.5 billion to upgrade its current grid to facilitate integration of distributed solar.

The IRP also addresses energy storage technologies such as flywheels, batteries and compressed air energy storage. Of these, batteries are a potentially attractive option. States the IRP: “Batteries can be used to provide energy for power station blackstart, peak load shaving, frequency regulation services, or peak load shifting to off peak. … The primary challenge facing battery systems is the cost. Other factors such as recharge times, variance in temperature, energy efficiency, and capacity degradation are also important considerations for utility-scale battery.” Still, says the IRP, Dominion is “actively engaged” in evaluating the potential for energy storage technologies.

In conclusion, states the IRP, “Virginia’s potential maximum solar build out is relatively small compared to other states in the U.S. and countries in the world.”

Why Dominion Sees Growing Electricity Demand in the 15-Year Future

electricity_demandby James A. Bacon

One of the more controversial forecasts contained in Dominion Virginia Power’s 2016 Integrated Resource Plan (IRP) is a projection that average electricity demand and peak demand in its service territory will increase at an annual rate of 1.5% annually over the next 15 years. If that forecast pans out, demand will outstrip the company’s 12.5% reserve margin when the current round of building projects is complete around 2021, and would create a supply shortage of 4.6 million megawatts by 2031 if no new capacity were added.

Setting aside questions of whether or not Dominion should include more renewable energy in its generation mix, environmentalists find the growth forecast problematic, arguing that electricity consumption is decoupling from economic growth nationally as new technologies become available, industries invest more capital in energy-efficiency, and some states adopt policies that promote efficiency.

I am agnostic on the issue but I believe this is one of the most important debates taking place in the electricity policy arena today. A higher demand forecast would justify a bigger investment by Dominion and Virginia’s other electric utilities, Appalachian Power and the Old Dominion Electric Cooperative, in new generating capacity. A lower demand forecast would support a more constrained approach to capital spending. The debate also raises the question of whether Virginia’s power companies should be moving more aggressively to implement energy-efficiency measures.

With this blog post I present the findings from Dominion’s 2016 IRP. I think it’s fair to say that Dominion has spent more man-hours and more dollars analyzing electricity demand in Virginia than anyone else. That’s not to say its forecasts are more reliable. Dominion concedes the enormous uncertainty regarding Clean Power Plant regulation, and the company may have institutional biases favoring faster demand growth. But it’s the best analysis we’ve got at the moment. I summarize Dominion’s discussion with the aim of stimulating discussion.

Dominion’s econometric model utilizes hourly DOM Zone data — the DOM Zone is the PJM Interconnection-designated zone inside which there are relatively few transmission constraints) and simulates both time-trend variables (electricity demand over time) and weather variables such as wind speed, cloud cover and precipitation. The model factors in time of day, day of week, holidays and seasonal effects, as well as unusual events such as hurricanes.


Graphic credit: Dominion. Click for larger image.

Overall, Dominion’s service territory is a summer-peaking zone, meaning that the highest demand is normally experienced during the summer. However, Dominion also has a weaker, winter peak, which on rare occasions such as the polar vortex a couple of years ago, is stronger than the summer.

While electricity demand has slowed in some sectors as energy-efficiency makes inroads, Dominion expects growing consumption in other areas — PCs, laptops, tablets and other digital devices; electric vehicles (primarily during evening hours); and data centers.  Consolidating data storage in hyper-efficient cloud facilities work to reduce overall overall demand, but the trend displaces consumption from scattered locations in the East Coast to Northern Virginia, which may be the most competitive location in the world for data storage due to its access to high-capacity fiber cable. While data centers do not create many jobs, economic developers like them because their enormous capital investment in servers contributes millions of dollars in local government tax revenue.

Moreoever, the Virginia economy is more dynamic than the national average. Going forward,” states the IRP, “the Virginia economy is expected to rebound considerably within the Planning Period. The 2015 Budget Bill approved by the President and the U.S. Congress has significantly increased the level of federal defense spending for fiscal years 2016 and 2017, which should benefit the Virginia economy.” All other things being equal, a more vibrant economy means higher electricity consumption.

Dominion makes its 1.5%-per-year forecast despite committing to a 2007 Electric Utility Reregulation Act goal of reducing retail electricity consumption by 10% (based on 2006 consumption levels).

To advance that goal, the company has put into place energy-efficiency measures ranging from air conditioner recycling and residential low-income energy assistance to demand-response tariffs for households using smart meters. Also, to curb increases in peak demand, Dominion has instituted a Standby Generation rate schedule providing incentives for businesses to switch to backup generators if demand is overwhelming supply. The size of the standby program is relatively small, however. According to an IRP table, there were 16 events in the summer of 2015 and 12 in the winter, reducing demand by on average by two megawatts. (That compares to about 24,400 megawatts of generating capacity across the utility’s fleet.)


In the chart above, Dominion displays its calculations of how much various energy-efficiency and alternative-energy programs will cost on a per-megawatt of power conserved or generated. In many cases, the energy-efficiency programs provide the most bang for the buck. But they are limited in scale.

Moreover, it is difficult to calculate the benefits of investments in energy efficiency, states the IRP, because the pilot programs are under-enrolled and small numbers make it difficult to extrapolate to a larger scale. The analysis for one program showed a negative impact on consumption from an energy-efficiency program, while another suggested that for every 1% increase in the price of electricity, household cut consumption by 0.75%. The company considered both to be outliers. More typical is a finding that  1% increase in price leads to a 0.1% cut in consumption  — a ten-to-one ratio.

Despite the uncertainties, Dominion stated in its “short term action plan” that it will “continue to implement cost-effective DSM programs in Virginia and North Carolina.”

Strictest Clean Power Option Would Cost Customers $12.8 Billion, Dominion Says

transmission_lineby James A. Bacon

Meeting the strictest compliance option of the Clean Power Plan would cost customers of Dominion Virginia Power an estimated $12.8 billion in higher electric rates over the next 30 years, the power company revealed in its 2016 Integrated Resource Plan, which it submitted to the State Corporation Commission (SCC) today.

Three lower-cost options would pack a punch as well, costing an additional $5.1 billion to $6.0 billion more than the least-cost plan, which the SCC requires Dominion to examine.

Implementing the strictest plan would increase residential electric bills (with 1,000 kilowatt hours per month usage) by 26.5% in 2022, with a declining impact through 2030.

“Our assumption is that some kind of carbon regulation is coming,” Katherine Bond, Dominion’s Dominion director of public policy said in a press briefing. However, she added that there is enormous uncertainty over what direction that regulation will take. The company examined options based on four broad approaches the Environmental Protection Agency allows states to pursue.

A legal challenge to the Clean Power Plan appears to be headed to the U.S. Supreme Court, which could derail the whole regulatory initiative. However, the McAuliffe administration, which backs the plan, has ordered the Department of Environmental Quality (DEQ) to determine which regulatory option would be best for Virginia if the Clean Power Plan clears the high court. No consensus has developed among the stakeholders who have been meeting for several months to advise the administration.

The Virginia Chapter of the Sierra Club and other environmental groups are backing a “mass-based emissions” approach, which would cap carbon-dioxide emissions on utilities’ existing and new generating facilities. A second mass-based approach would cap emissions from existing power plants only, while two other strategies would limit CO2 emissions using intensity-based goals that limit CO2 emissions per kilowatt hour of power produced. The intensity-based approach would provide more flexibility and give Virginia room to grow its economy, but it would allow greater CO2 emissions.

“We are pleased to see that Dominion is now considering one alternative plan in compliance with the Clean Power Plan, Plan E, that includes capping new and existing fossil fuel sources,” said Glen Besa, director of the Virginia Sierra Club in a statement responding to the IRP. “While Dominion claims that Plan E is the most expensive alternative, it is important to note that most of this cost is attributable to Dominion’s inclusion of a new $19 billion nuclear reactor at North Anna.” That reactor alone could raise customer rates by as much as 25%, found an analyst for the Attorney General’s office.

Also, Besa told Bacon’s Rebellion this afternoon, the IRP Dominion submitted last year recommended a plan that would increase CO2 emissions by 60%. He had not had a chance to examine the 2016 IRP, but he doubted the low-cost plan differed enough to change the percentage by much.

The low cost plan includes the following:

  • Three combined cycle gas units one one location: 3,183 megawatts
  • Two combined cycle gas units at a second location: 1,062 megawatts
  • Combustion turbine: 2,288 megawatts
  • Solar: 1,000 megawatts
  • Offshore wind: 12 megawatts

By contrast Dominion’s Plan E (the lowest carbon-emitting scenario) envisions the addition of the following capacity:

  • Two combined-cycle natural gas units: 3,186 megawatts
  • Combustion turbine: 1,373 megawatts
  • Solar: 8,000 megawatts
  • Nuclear: 1,452 megawatts
  • Offshore wind: 12 megawatts

Dominion cites two reasons for the high expense of the lowest carbon scenario. First, it relies heavily upon solar energy. Although the “fuel” — the sun — is free, its capacity rating, or the percentage of time a solar facility actually generates electricity is lower than for other fuel sources. Moreover, it is intermittent, which means Dominion cannot necessarily call upon it when needed, which means it must maintain backup capacity. Second, the low-carbon approach rules out coal and most new natural gas, leaving only one low-carbon alternative to provide base generation — nuclear. The lowest-carbon scenario is the only one in which Dominion envisions building the North Anna 3 unit.

Dominion did not recommend any of the alternatives it examined, but it did recommend against the mass-based programs because they offer the least flexibility in achieving compliance.

While electricity consumption has leveled off nationally, Dominion sees it continuing to grow in Virginia at an average 1.5% growth rate over the next 30 years, creating a large and growing capacity gap. Environmentalists contend that the growth rate could be reduced significantly if Dominion pursued energy efficiency strategies more aggressively. Dominion counters that Virginia’s population and economy are growing, driven by a significant degree by the growth of the energy-intensive data center industry in Northern Virginia.

Treated Coal Ash Water Flows Today

Jason Williams, environmental manager, addresses members of the Richmond media.

Jason Williams (right), environmental manager, addresses Richmond media.

by James A. Bacon

After months of controversy, Dominion Virginia Power will start draining today more than 200 million gallons of water from its coal ash ponds at the Bremo Power Station. “We’re treating to levels that will be fully protective of the river,” Jason Williams, the environmental manager in charge of the project, told a media gaggle invited yesterday to view the water treatment facilities.

Treating the water to meet quality standards protective of aquatic life will cost about $35 million at Bremo and take a year or more, depending on how smoothly the process goes and how much rainwater is added to the coal ash ponds during the period. If Dominion consistently meets those standards, Department of Environmental Quality (DEQ) officials say that the odds of event negatively impacting human health or aquatic life in any given year are less than three in one thousand.

While the eight-step water-treatment system is basically the same design that the company submitted with its permit application to the Department of Environmental Quality, Dominion agreed to stricter protocols for treating, monitoring and testing the water quality in a settlement with the James River Association.

Coal ash is the residue from coal combustion, and it contains heavy metals that are toxic in high enough concentrations. Historically, electric utilities have stored the ash in ponds where it mixed with water to create a sludge. To prevent leaks and spillage from the ponds, the Environmental Protection Agency (EPA) is requiring power companies to remove the water and then find a safe place to store the ash. The James River Association has signed off on Dominion’s plan to de-water the coal ash at Bremo. Meanwhile, Dominion is applying for a separate permit to cover the disposal of the de-watered ash, which will create its own set of issues and potentially generate a fresh controversy.

For now, though, everyone is on board with the de-watering plan. Williams outlined the eight-step process, which he calls “state of the art.”


Graphic credit: Dominion (Click for larger image)

  • Aeration. Water from the coal ash pond is piped into a tank where the addition of air facilitates the water-cleaning process.
  • pH adjustment. Acidity is reduced, which encourages particles in the water to separate and settle.
  • Clarification. Chemicals are added to the water to help the particles clump together so they will settle out of the water.
  • Settling tanks. Solids from the clarification process are separated from the water, collected, and disposed of in a landfill.
  • Filtering. The water is passed through filters to remove even more particles.
  • Enhanced treatment. The water is tested. If certain constituents such as heavy metals remain close to trigger levels agreed to by the James River Association, the water is run through an extra piece of equipment to remove them.
  • pH adjustment. If needed, the pH level of the water is adjusted back to levels that are safe for the river.
  • Holding tanks. The water is pumped to one of four 950,000-gallon holding tanks where it is tested again before being released into the water. Dominion expects the water in these tanks to meet standards, but if it doesn’t, it will be routed through the treatment process again.

Continue reading

Once in Four Lifetimes

virginia_fishThe conservative assumptions behind Virginia water-discharge permits, says DEQ, reduce the odds of harming aquatic wildlife to fewer than three incidents in a thousand years.

by James A. Bacon

Earlier this year Dominion Virginia Power was granted permits to drain water from coal ash ponds at its Bremo and Possum Point power stations, treat the water to remove heavy metals, and discharge the effluent into the James River and Quantico Creek. Citizens have understandable concerns. What limits did DEQ place on the heavy metals in the wastewater? How were the limits determined? And what assurances do Virginians have that those limits will safeguard the public health and the health of aquatic species?

In a nod to transparency, Virginia’s Department of Environmental Quality (DEQ) has posted the permits online. To get a flavor, you can view the Virginia Pollutant Discharge Elimination System (VPDES) permit for the Bremo Power station here. Unfortunately, that document is indecipherable to the layman. DEQ permit writers live in a world all their own, replete with jargon, acronyms, arcane regulatory procedures and complex statistical formulations that only DEQ, power companies and the environmentalist groups that sue them seem to understand.

Wondering how DEQ set the heavy metals limits listed in its permits, from arsenic and mercury to lead and selenium, I sat down recently with Fred Cunningham, DEQ’s manager-office of water permits, and Allan Brockenbrough, manager-VPDES permits. The two career DEQ employees walked me through the process. Because the Possum Point permit is under appeal, they did not address the coal-ash permits specifically. But they said that the procedures for apply to all industrial sites, including power stations with coal ash ponds.

The primary message they wished to convey is this: DEQ permits create an ample safety buffer. Accounting for just two of the conservative assumptions built into the process, say Cunningham and Brockenbrough, the chances of a scenario occurring that endangers either the public health or aquatic life are in the realm of thrice every thousand years. The incorporation of other conservative assumptions reduces that incidence even further.

Brockenbrough put it this way: “When you make one conservative assumption, and a second, and a third, and a fourth, they all build on each other.”


Heavy metal discharge limits in Dominion’s Bremo permit

Virginia environmentalists active in the coal ash debate have not taken issue with the DEQ methodology, which they neither criticize nor endorse. Their main thrust has been to ensure that wastewater is monitored and tested with sufficient frequency and duration to make the public comfortable that Water Quality Standards are being met. Also, in the case of Possum Point permit, the Potomac Riverkeeper Network has appealed on the grounds that Dominion should employ Best Available Technology, even if the resulting water quality exceeds DEQ standards. If Virginia can reduce at reasonable cost the level of pollutants released into Virginia waters, even if they exist only in trace elements, why not do it?

By contrast, John Craynon, director-environmental programs at Virginia Tech’s Center for Coal and Energy Research, says, “Our standards are very conservative. … I think the DEQ has proposed a standard that is protective and does not put an undue burden on all of us.” Just because we are capable of detecting the presence of heavy metals in parts per trillion does not mean we should regulate them at that level. Trace amounts of these elements exist in the environment and organisms have evolved to co-exist with them. Compelling industry to reduce levels even further is an exercise in diminishing returns. “Is it worth it? Some would say yes. I do a running cost-benefit analysis in my head.”

The federal Environmental Protection Agency sets the legal framework for administering the Clean Water Act, and DEQ operates within that framework. Based on the latest scientific knowledge, EPA continually updates federal water quality standards for some 130 different constituents including heavy metals, organic compounds and pesticides known to pose a threat to the health of humans and aquatic creatures. It is DEQ’s job to apply these standards to specific situations when writing permits.

DEQ determines a safe level for each constituent (measured either in micrograms per liter, or parts per billion) for three criteria: acute (short-term) impact on aquatic organisms, chronic (long-term) impact on aquatic organisms, and human health impact. In the first of many conservative safeguards, DEQ applies the most restrictive of the three numbers, even if that level provides more protection than is deemed essential for the other two.

Another conservative assumption DEQ builds into its permits is its “return interval” — the period of time over which a one-time, worst-case scenario is evaluated. The Water Quality Standards approved by EPA allow for instream standards to be exceeded once every three years. DEQ uses a ten-year interval when setting standards.

As translated into the permits for Bremo, DEQ’s discharge limits will protect the river water outside a mixing zone no larger than 16 feet wide and 2,000 feet long (about 1/3 of an acre) in the worst drought scenario predicted for a ten-year period. The vast majority of time, the area within the mixing zone where pollutants exceed Water Quality Standards will be much smaller — at times undetectable — although DEQ does not calculate how large it will be in any circumstance except the 10-year, worst-case scenario. Continue reading

Coal’s Messy End Game

coal_minersby James A. Bacon

The U.S. coal industry is in collapse. Market forces in the form of cheap, abundant natural gas have put coal at a huge competitive disadvantage while environmental initiatives have gutted demand by compelling the shutdown of coal-fired power plants not worth retrofitting with scrubbers. Earlier this week Peabody Energy, the largest coal producer in the country, announced that it would seek bankruptcy protection. Only one company in the Dow Jones Coal Index, Consol Energy, has avoided that fate.

Writing in Slate Magazine, Daniel Gross poses an interesting question:

When companies file for bankruptcy, the fact that they can’t meet their obligations to creditors like banks or bondholders isn’t that much of an issue. They can absorb the loss and wind up with ownership of the company. But bankrupt coal firms will have a hard time meeting their obligations to the environment, to employees, and to retirees. Which means they will either need a bailout or they will suffer further obloquy when they walk away from commitments.

Coal mining in Central Appalachia is an immensely destructive business, especially strip mining and mountaintop removal, which quite literally moves mountains, alters drainage flows, and releases potentially toxic elements into the water. Federal regulations require coal companies to stabilize the land in order to reduce environmental hazards. When coal was booming a few years ago, that wasn’t a problem. With major coal companies going bankrupt, there are growing questions whether coal companies can fulfill their obligations.

Virginia-based Alpha Natural Resources has $640 million in self-guaranteed liabilities in reclamation costs, reports the Washington Post. Will a western Virginia bankruptcy court judge honor the debts of creditors and suppliers or obligations to the public?

Meanwhile, coal industry pension funds, which have always been shaky, now are in deep doo-doo. The United Mine Workers of America’s 1974 pension plan was said last year to be $2 billion under-funded.  The plan asked for participating unionized companies to increase their contribution by 10% to $6.05 per union employee per hour worked, along with benefit cuts for future employees. But it is questionable how long bankrupt coal companies can sustain such payments. Who, if anyone, will make good promises made to retired coal miners?

Bacon’s bottom line. Coal is a dirty, unsafe fuel, and most of us won’t miss it. But the transition to a clean-energy economy will be messy. For Virginia’s coalfield region, the demise of the coal industry doesn’t mean just the loss of jobs, as debilitating as that will be. It could well mean environmental clean-ups never completed and pensions never paid.