Category Archives: Environment

The Right Way to Test for Coal Ash Contaminants

A North Carolina riverkeeper inspects testing samples of coal ash taken from the Dan River.

A North Carolina riverkeeper inspects testing samples of coal ash taken from the Dan River. Photo credit: WRAL.

So, it looks like the there will be a pause in the solid-waste permitting process for Virginia coal ash. Governor Terry McAuliffe had submitted an amendment to legislation that, if approved, would require Dominion Virginia Power to compile more information on contamination around its coal ash sites and study alternative closure methods before the state issues the permits. Now Dominion has decided to go along, which means political opposition to the idea could evaporate.

“We concur that it is a prudent course of action to seek and consider an evaluation of the assessments on the appropriate closure methods based on the individual features of each site before seeking necessary solid-waste permits,” wrote Dominion CEO Thomas F. Farrell II. “Dominion finds the proposed amendments to Senate Bill 1398 to be workable, and is committed to completing the site assessments before pursuing solid waste permits regardless of the outcome of the legislation.”

McAuliffe’s amendment would restore key provisions to a bill co-sponsored by Sens. Scott A. Surovell-D-Fairfax, and Amanda F. Chase, R-Chesterfield, whose legislative districts include Dominion’s Possum Point Power Station and Chesterfield Power Station, each of which has millions of tons of coal ash to dispose of. (See the Richmond Times-Dispatch story here.)

Dominion had originally opposed the testing and study provisions, which were stripped out by the House of Delegates. But if the power company drops its opposition to McAuliffe’s amendment, as Farrell’s letter indicates, Surovell and Chase likely will get their way.

According to the bill summary, HB 1398 will require owners of coal ash ponds (1) to identify water pollution emanating from the ponds and address corrective measures, and (2) evaluate the feasibility of “clean closure.” Clean closure would entail removing the coal ash from ponds where it has been stored to lined landfills. Dominion has estimated that the cost of landfilling could amount to $3 billion, but environmental groups have argued that the cost would be much lower if the utility recycled the material as an additive to cement and other products.

Bacon’s bottom line: Pausing the permitting process to get a better handle on what’s happening at the coal ash ponds is a good idea. Frankly, despite considerable testing by both Dominion, environmental groups and even Duke University, little can be said with certainty about the process at each of Dominion’s four sites by which groundwater migrates through the coal ash and contaminates either well water or nearby rivers and streams.

Any testing regime must be rigorous enough to provide definitive answers. The last thing we need is set of ambiguous results that Dominion and environmental groups try to spin to their advantage in another contest of P.R. and political clout. Any credible testing program should outside experts, perhaps from Duke or perhaps from a Virginia university, who can identify the questions that to be answered and what protocols will provide definitive answers.

Dominion has conducted tests on its property and found little evidence of contamination at Possum Point, Chesterfield and the Bremo Power Station, but a federal judge recently used Dominion data to conclude that coal ash its closed Chesapeake plant was contaminating groundwater. Testing by riverkeeper groups of groundwater and surface waters just outside of Dominion property show elevated levels of heavy metals which, at sufficient concentrations, can be toxic to aquatic life and human health. Additionally, Duke University has conducted extensive testing in North Carolina and Virginia using “forensic tracers” that have found elevated levels of heavy metals in groundwater near Bremo and Chesapeake. But other Duke tests have found that elevated levels of the carcinogen hexavalent chromium, also associated with coal ash, is endemic in piedmont groundwater and in many cases cannot be attributed to the coal combustion residue.

Complicating any analysis is the fact that trace levels of heavy metals and carcinogens are frequently found in groundwater and surface water as the result of natural processes. Levels vary depending upon local geology. The existence of trace elements of heavy metals in groundwater near coal ash ponds is not in itself proof that the heavy metals came from the coal ash. The trace elements could be ubiquitous in the area, but no one knows unless tests are conducted some distance from the power plants. Ideally, any testing regime for Dominion’s coal ash ponds would adjust for background levels of contaminants.

Another complication is ascertaining the movement of groundwater. For example, the water from several wells near Possum Point have shown elevated levels of heavy metals. It is easy to deduce from the proximity of the wells to coal ash ponds that the contaminants come from the ponds. But to demonstrate the point conclusively, one must show that the groundwater migrates from the coal ash ponds toward the wells, and not in some other direction. To make that proof, it is necessary to conduct extensive drilling and create detailed maps that mark the geographic scope and elevation (in feet above sea level) of the underground water and determine the direction of the water flow. Only if it can be documented that underground water is migrating from the coal ash pond toward the wells can one reasonably conclude that the coal ash is to blame for elevated levels of well-water contaminants. If the water is migrating away from the wells, the well-water contaminants probably have another source.

Adding another layer of complexity to the analysis is estimating how much contamination the groundwater picks up while migrating through coal ash. Dominion maintains that its coal ash pits do not come into contact with the water table; the deepest part of the ponds have a higher elevation than the underground water table. However, using Dominion’s own maps, the Southern Environmental Law Center (SELC) contends that the bottom reaches of the coal ash ponds at Bremo and Chesterfield intersect with the water table. If the SELC is right, groundwater that migrates through a portion of the coal ash could pick up contaminants along the way.

The question then arises, how long must the water be in contact with the coal ash in order to pick up trace metals? That is a function of the chemistry of the coal ash, how tightly or loosely the metals are bound to inert materials, and the speed of water migration, which depends upon the permeability of the clays and rocks. If the groundwater comes into contact with only a small percentage of the coal ash for a short time, the leeching of heavy metals could well be minimal.

If it can be demonstrated that measurable levels of metals leach into the groundwater, another question must be answered: What volume of contaminants, and how rapidly, does the groundwater feed into surrounding rivers and streams? While U.S. District Court Judge John A. Gibney Jr. found that Dominion’s Chesapeake Coal ash ponds did contaminate the groundwater and that the groundwater did reach the Elizabeth River in violation of the Clean Water Act, he also found no damages because the contaminants were so diluted by the massive water volume of the river that aquatic and human health were unaffected. Continue reading

Electric Reliability and Energy Mix

 Portfolios with high mixes of coal, nuclear and natural gas have the greatest electric reliability.

The purple line shows the Composite Reliability Index (CRI) of different energy-mix portfolios. Portfolios with high mixes of coal, nuclear and natural gas have the greatest electric reliability. Portfolios with large wind components tend to be more reliable than those with solar.

Electric utilities in the 13-state PJM Interconnection regional transmission territory have a balanced resource mix — coal, nuclear, gas and renewables — that is “well equipped” to support reliable operation of the regional grid, PJM has found in a new report, “PJM’s Evolving Resource Mix and System Reliability.”

But continued evolution of the resource mix — particularly the decommissioning of coal and nuclear plants and increasing reliance upon natural gas and renewables — could create reliability issues in the future.

PJM is in charge of maintaining the integrity of the electric grid within its territory, which includes all of Virginia. The study analyzed a spectrum of “portfolios” with different fuel mixes to see how they would affect a variety of electric reliability attributes such as voltage control, frequency response, and the ability to ramp production up and down as needed.

Of particular relevance to the ongoing energy debate in Virginia, PJM found that portfolios with 20% or greater of solar energy in the fuel mix would be “infeasible” because they would be unable to reliably meet night-time requirements. There don’t appear to be any upper bounds for natural gas, but excessive dependence upon gas could create vulnerabilities under a “polar vortex” scenario of sustained, bitterly cold temperatures.

In Virginia, Dominion Virginia Power has emphasized the importance of fuel source diversity, including coal and nuclear. Dominion’s plans for nuclear, which include extending the longevity of its Surry and North Anna nuclear units by an extra 20 years and possibly building a third nuclear unit at tremendous expense at North Anna, have proven particularly contentious. Solar constitutes a small percentage of Virginia’s fuel mix but is fast growing, and environmentalists are pushing for a much bigger role.

Across the PJM region, notes the study, the fuel mix has become more evenly balanced over time. In 2005, coal and nuclear generated 91% of the energy on the PJM system. But between 2010 and 2016, extensive coal capacity was retired and replaced mainly with gas and renewables. PJM’s installed capacity in 2016 consisted of 33% coal, 33% natural gas, 18% nuclear and 6% renewables and hydro. PJM has said in the past that the transmission grid was flexible enough that it could accommodate up to 30% renewables.

Each fuel source has advantages and disadvantages in helping electric utilities balance electricity supply and demand while sticking to tight parameters for frequency and voltage. Coal and nuclear are less responsive to changes in demand, taking far longer to ramp production up and down. Wind and solar are easy to turn off but, due to the variability of the wind and sun, cannot be turned on at will. Natural gas tends to be the most flexible, and PJM’s most reliable portfolios include large contributions from gas. Electric batteries also would provide considerable flexibility, but PJM does not foresee them being deployed on a large scale within the time-frame of the study.

States the study:

  • Portfolios with the lowest unforced capacity shares of wind and solar tend to have the lowest composite reliability indices. (Note: “unforced capacity” refers to capacity in normal operating conditions as opposed to maximum “nameplate” capacity.)
  • Composite reliability indices generally improve as capacity shares of nuclear, coal and natural gas increase.
  • When coal and nuclear units are retired and replaced, portfolios with the highest composite reliability indices tend to be ones in which natural gas is the predominant replacement resource.

Bacon’s bottom line: PJM makes no judgment about the “best” fuel source mix, and it does not say that the most reliable fuel mixes are necessarily more desirable. If the goal is to increase renewables for reasons of reducing CO2 emissions, it is possible that some fuel mixes are reliable enough to accomplish both reliability and sustainability objectives.

Still, the PJM analysis suggests that high-renewable fuel mixes are “at risk for underperformance” and likely will need “additional technology requirements and/or new market rules” to ensure electric reliability.”

Avoiding Blackouts with a Remedial Action Scheme

Under its "Remedial Action Scheme" Dominion may not have to implement rolling blackouts in the Peninsula on high-risk days.

Under its Remedial Action Scheme Dominion may not have to implement rolling blackouts in the Peninsula on high-risk days.

Two years ago Dominion Virginia Power warned of dire consequences to the Virginia Peninsula if the company could not build a 500 kV transmission line across the James River. An analysis prepared by engineering consulting firm Stantec and submitted to the U.S. Corps of Engineers left little to the imagination:

Dominion will be required to implement pre-contingency load shedding (i.e. rolling blackouts) in the [North Hampton Roads Load Area] to prevent the possibility of cascading outages impacting the reliability of the interconnected transmission system. … It is estimated that rolling blackouts would initially occur 80 days a year and would continue to increase in number as load continues to grow in the area. …

The potential exists that up to 50% of the customers in this load area could be without electricity for days or even weeks until the event which caused the failure could be fixed.

Yesterday I posted an article based on an interview with Steve Chafin, Dominion director of transmission planning and strategic initiatives, that seemed to tell a different story. While the utility still said the Peninsula will be at risk for 50 to 80 days a year after shutting down the Yorktown Power Station’s No. 1 and No. 2 generators April 15, the ability to continue running the No. 3 generator up to 29 days a year will reduce that threat to about 50 days. Only if an unplanned event knocked out a transmission line — something that has happened only six times the past ten years — on one of those days would Dominion have to shed load. While there are no guarantees, Chafin told me, “We think we can get through the summer without any rotating blackouts.”

After publishing the article, I got to thinking about the marked difference in tone. Two years ago, when Dominion was trying to push the Surry-Skiffes project through regulatory approval in the face of intense opposition by preservationists, the company was stressing how disastrous things would be if the project wasn’t built. Now that the permit review by the Army Corps of Engineers is reaching its final stages and a mitigation settlement seems imminent, Dominion is downplaying the risk.

Yesterday I asked Chafin and Le-Ha Anderson, a Dominion spokesperson, to explain the change in rhetoric. They stand by what Dominion said then, and they stand by what Dominion says now, and they say there’s a legitimate explanation.

The difference between then and now is that Dominion has set up a Remedial Action Scheme (RAS).

Dominion worries about an uncontrolled, cascading blackout emanating from the Peninsula, the most vulnerable zone in the Dominion electric system and one of the most fragile in the 13-state PJM Interconnection territory. If blackouts erupted there, Dominion’s grid models can’t predict where they would stop. The United States conceivably could experience an outage as widespread as the infamous 2003 Northeastern blackout that knocked out power to millions.

With approval from the Southeastern Electric Reliability Council and PJM Interconnection, Dominion has set up an RAS to isolate the Peninsula if an unplanned outage occurs. “We put in an automatic, specialized relay scheme,” says Chafin. “If it senses certain conditions, it will immediately drop load to 150,000 customers.” The draconian action will prevent a cascading shut-down of transmission lines emanating from the Peninsula to points beyond.

Before the Remedial Action Scheme, Dominion would have had to implement rotating blackouts on high-load days before a component failure or other disruption occurred. Because the RAS responds immediately when needed, it allows Dominion to implement blackouts after the disruption.

While implementation of the RAS under a worst-case scenario would cause a massive outage on the Peninsula, it would nip in the bud an uncontrolled blackout that could rip through the nation’s electric grid. The chances of it occurring are remote, however, and it reduces the necessity of initiating precautionary, controlled blackouts when the Peninsula region reaches peak electric load some 50 or so times a year.

“We have a responsibility to provide reliability to our customers. We have an equally important responsibility to protect the safety and integrity of the grid,” Chafin says. “The automation will help to reduce the risk on a short-term and temporary basis.”

The Remedial Action Scheme will be available until the Surry-Skiffes transmission line receives regulatory approval and construction is complete, a process that will take at least another 18 months.

“We’ve been working on a Peninsula solution for a long time,” says Anderson. “We filed in 2013, and have worked with the Corps for almost four years. This is a serious situation. … We’ve had to look at what other things we can do in the meantime. This is a temporary, short-term tool that will help get us through the most critical period.”

Time to Panic Over the Closing of Yorktown Units? In a Word… No

Yorktown Power Station.

Yorktown Power Station. Photo credit: Daily Press

The day, April 15, is fast approaching when Dominion Virginia Power will be compelled by federal regulations to shut down two coal-fired generating units at the Yorktown Power Station, exposing the Virginia Peninsula to the risk of blackouts.

When the Yorktown units are shuttered, the utility will have enough electric power to supply the half million-person region from the outside most of the time. But during periods of peak demand, usually during the summer, an accident knocking one of those lines out of commission will put the region only one more incident away from uncontrolled, cascading blackouts that could spread to Norfolk, Richmond and beyond. Rather than incur any chance of disaster, PJM Interconnection, the organization that controls the transmission grid for a 12-state region that includes Virginia, would “shed load” — in other words, cut off electric power to some residents and businesses on the Peninsula.

Dominion’s proposed backup, the Surry-Skiffes transmission line, remains in a state of regulatory limbo while the U.S. Army Corps of Engineers negotiates ways to mitigate the line’s impact on a near-pristine stretch of the James River near Jamestown. Even if the Corps gave Dominion a permit tomorrow, it will take 18 months — and two summers — before the line can be built.

If I were a Peninsula business or resident, I’d be wondering, is it time to panic yet? I put the questions to Dominion: How frequent will the blackouts be and how bad will they be?

The answer: The threat is real but small in any given year, and a blackout, if it occurs, is likely to be limited in scope and duration. However, while the Peninsula might skate through the next year or two without a blackout, the situation is intolerable over the long run, Dominion warns. The Peninsula is the region most exposed to blackouts in the Dominion system and possibly the most vulnerable in the entire PJM transmission grid.

“This is a serious situation,” says Steve Chafin, Dominion director of transmission planning and strategic initiatives. When three things come together — (1) temperatures are running high, (2) the Yorktown 3 unit isn’t running, and (3) an accident knocks out a transmission line or sub-station — PJM likely will have to shed load.

Assuming normal weather conditions, the Peninsula will experience between 50 and 80 “high risk” days, Chafin says. Peak consumption is likely to occur in the summer, when temperatures are highest, although a few days may occur in the winter when temperatures are extremely low.

Although the company is closing two coal-fired units, the Environmental Protection Agency will allow it to run Yorktown 3, a oil-fired unit, 8% of the time, or up to 29 days. Using Yorktown 3 as a backup will reduce the number of vulnerable days to between 20 to 50.

Transmission lines to the Peninsula have been knocked out by accidents, component malfunctions or other causes six times in the past 10 years — an average of once every 20 months. (There have been two incidents in the past 10 years in which two simultaneous outages occurred.)

To reduce the odds of such mishaps shutting down a transmission line, the utility has been increasing its patrols of electric lines, boosting sub-station inspections and running infrared scanner. “This is not a normal mode of operation,” says Chafin. “We don’t patrol our transmission lines this frequently.”

If a once-every-twenty-months line outage occurs during one of the 20 to 50 at-risk days of heavy consumption when Yorktown 3 isn’t running, the electric grid will be at risk of an uncontrolled, cascading blackout. PJM, working in coordination with Dominion, will decide whether or not to shed load.

Should it become necessary to cut electricity consumption, the goal will be to disrupt as few people as possible and spare critical infrastructure such as hospitals and water treatment plants. PJM and Dominion would continuously run contingency models to determine the best course of action.

“Our goal is to avoid the need for temporary service interruptions, but should it become necessary, we will do all we can to limit the number of customers and duration,” Chafin says. “In the end, these are temporary measures to protect the larger grid from widespread, uncontrolled outages.”

Should blackouts occur, they likely would not last all day or affect the entire Peninsula. The company would close no more circuits than needed to drop electricity consumption to within a safe range. Giving a hypothetical example, Chafin says, “We might do two or three blocks of circuits of a few thousand customers for an hour or two.”

Dominion also would ask Peninsula customers to voluntarily conserve electricity.  “The more the conservation, the shorter the duration and the fewer people affected,” he says.

With a little luck the Peninsula might escape unscathed, Chafin says. “We’re running drills to make sure we’re ready. We think we can get through the summer without any rotating blackouts.”

Chesapeake Coal Ash Ruling — Advantage Dominion

Judge John A. Gibney Jr.

My initial reaction to Judge John A. Gibney Jr.’s ruling in Virginia’s first coal ash-related federal court case was to call it a draw. As I blogged yesterday, both the Sierra Club and Dominion Virginia Power found aspects of the judge’s order that supported their positions. But as I sort through the implications for the ongoing debate over coal ash in Virginia, I’m thinking that Dominion was the real winner in the long run.

True enough, the Sierra Club and its attorneys with the Southern Environmental Law Center (SELC) did win one important tactical victory: Gibney found that arsenic-tainted groundwater passing through the coal ash ponds at Dominion’s former Chesapeake Energy Center (CEC), did, in fact, reach the Elizabeth River in violation of the Clean Water Act.

Here’s how Seth Heald, chair of the Sierra Club’s Virginia chapter, framed that finding in a press release:

A federal court has found Dominion responsible for breaking the law and polluting the Elizabeth River. That is important for all Virginians who seek to hold the utility responsible for its mishandling of toxic coal ash. Now we must push Dominion to do the right thing and get this toxic ash out of the groundwater and away from the river, which is highly susceptible to disastrous flooding from sea-level rise and other climate-change effects.

But the judge also found that Dominion had been a “good corporate citizen,” had cooperated with Virginia’s Department of Environmental Quality (DEQ) “every step of the way,” and “should not suffer penalties for doing things that it, and the Commonwealth, thought complied with state and federal law.”

More importantly, Gibney applied what is, in effect, a cost-benefit test to any proposed remedy. While it is true that a tiny volume of leachate reaches the Elizabeth River, arsenic concentrations have been rendered harmless by dilution in the massive volume of river water. No threat to aquatic life and human health has been detectable so far. Unless evidence emerges that arsenic levels are reaching dangerous levels, he saw no justification to spend upwards of $600 million to excavate and remove the coal ash.

Gibney also found Dominion’s remedy of “monitored natural attenuation” — in effect, letting nature run its course — to be inadequate as well. He ordered Dominion to conduct more extensive monitoring of sediment, water and wildlife in and around the Chesapeake cite, and to report the results to the Sierra Club’s counsel and the DEQ. “In the event of a significant change in the amount of arsenic in the water or sediments,” Gibney wrote, “either party may move the Court for further relief.”

But Gibney’s cost-benefit test favors Dominion as the coal-ash controversy unfolds. Riverkeeper groups have opposed Dominion’s requests for solid-waste permits at its Bremo and Possum Point power stations. They argued, as the Sierra Club did in the CEC case, that evidence of contaminated groundwater migrating into nearby water bodies is grounds for removing the coal ash to lined landfills away from the water regardless of expense. But the application of Gibney’s logic to future cases would mean that demonstrating the leakage of small volumes of contamination into surface waters is not sufficient to seek a massively expensive remedy. The leakage must be on a scale to affect aquatic health and human safety.

Over a half century of burning coal at the Chesapeake power plant, Dominion accumulated 3.4 million tons of combustion residue and disposed of it in coal ponds. The ash contained high levels of arsenic — an estimated 150 tons. In 2014, samples of groundwater from ten wells around the ash landfill showed arsenic concentrations higher than 10 micrograms per liter, the groundwater protection standard set by DEQ. At one location, the judge noted, the arsenic concentration reached 1,287 micrograms per liter.

Gibney accepted the Sierra Club’s arguments that groundwater migrates from the coal ash to the surface waters of the Elizabeth River and its tributaries. In so doing, he rejected Dominion’s contentions that the groundwater was unconnected to the surrounding water bodies, and that arsenic traces found in the Elizabeth River originated from other industrial sources. Wrote the judge:

Dominion argues that because sediments move upstream and downstream with the tides, it is impossible to tell where the sediments used for the poor water samples originally came from. Although some tidal action may move sediments around, it defies logic to argue that an enormous amount of arsenic does not contribute to the arsenic in soil and water right next to it, especially given the evidence of groundwater movement from the mound outward.

While the evidence shows that Dominion does discharge some arsenic into nearby surface waters, Gibney reasoned, “it does not show how much.”

The Court cannot determine how much groundwater reaches the surface waters, or how much arsenic goes from the CEC to the surrounding waters. .. What the Court does know, however, is that the discharge poses no threat to health or the environment. All tests of the surface waters surrounding the CEC have been well below the water quality criteria for arsenic….. The CEC is surrounded by an enormous body of water, and even a large arsenic discharge would amount to a drop in the bucket.

Continue reading

Dominion, SELC Spin Coal Ash Ruling as Victory

Dominion Virginia Power and the Southern Environmental Law Center (SELC) are both declaring victory after a ruling by a federal judge regarding Dominion’s disposal of coal ash at its retired Chesapeake Energy Center.

U.S. District Court Judge John A. Gibney ruled today that the coal ash ponds are contaminating the Elizabeth River with arsenic and that the process of “natural attenuation,” or letting nature take its course, is a “completely ineffective solution,” says a press release issued by the SELC, which represented the plaintiff, the Sierra Club.

“The judge agreed with the Sierra Club’s experts, and rejected the testimony of Dominion experts who said arsenic does not reach the Elizabeth River,” said the statement.

But Dominion found much to celebrate in Gibney’s ruling as well. “The court has confirmed that there has been no threat to health or the environment resulting from the coal ash stored at its former Chesapeake Energy Center,” said a Dominion statement. “The court noted there has been ‘no evidence that shows any injury … has occurred to health or the environment.”

Furthermore, the ruling noted that Dominion had abided by all permits and “should not suffer penalties for doing things that it, and the Commonwealth, thought complied with state and federal law.” Accordingly, the court imposed no penalties on Dominion.

That’s the breaking news. I’ll try to have more tomorrow regarding the implications of the ruling for coal ash controversies at Dominion’s Bremo, Possums Point and Chesterfield power stations.

Fix the Broken Regulatory Process

There must be a better way for federal agencies to review infrastructure mega-projects.

A few days ago, I asked why, after three-and-a-half years, the U.S. Army Corps of Engineers has yet to give a yea or nay on Dominion Virginia Power’s permit request for the Surry-Skiffes Creek transmission line. The issue I’m raising isn’t what the Army Corps decides but how long it takes to reach a decision. Because of the interminable time spent pondering the permit application, citizens and businesses on the Virginia Peninsula will be at risk of blackouts this year and next, if not longer.

Today, the Richmond Times-Dispatch highlights the frustrations expressed by Diane Leopold, CEO of Dominion Transmission (DT), sister company of Dominion Virginia Power and managing partner of the proposed $5 billion Atlantic Coast Pipeline (ACP).

“To make these beneficial investments we need certainty from federal agencies. Not a rubber stamp, but a rational path forward with clear processes, reasonable schedules and reasonable decisions,” said Leopold in testimony to the U.S. Senate Committee on Energy and Natural Resources.

The pipeline requires more than 18 major federal permits and authorizations from the Federal Energy Regulatory Commission, the U.S. Army Corps of Engineers, the National Parks Service, the U.S. Forest Service, the Environmental Protection Agency and the U.S. Fish and Wildlife Service. The most visible hang-up at the moment, as judged by Robert Zullo’s article in the T-D, appears to be with the Forest Service.

Dominion says it will use state-of-the-art technology and best practices that will minimize the risk of landslides and erosion on steep mountain slopes. But environmentalists claim that Dominion is under-estimating the landslide risk, and it appears that the Forest Service shares their concerns. Dominion is convinced that it’s right, and its foes are equally persuaded that they’re right. The debate will never be settled by having one side back down.

Why does this have to be so hard?

Instead of a time-consuming bureaucratic battle, why not just specify the desired erosion-and-sediment-control outcomes and require the pipeline to meet them? A reasonable approach would entail careful monitoring of land crossed by the pipeline to detect landslides and other forms of erosion — a cost that ACP would have to absorb. All monitoring data would be made available to the public so government agencies and environmental groups could inspect them to ensure the pipeline was fulfilling its responsibilities. ACP would be required to pay the full cost of restoring mountain slopes and compensate nearby landowners or water authorities for any damages. Perhaps ACP would be required to maintain insurance or post a bond sufficient to guarantee the damages are covered.

There should be one debate over the standards appropriate to steep mountain slopes, and those standards should apply to everyone who wants to build an interstate pipeline in comparable terrain. The purpose of regulation should not be to prescribe how pipelines do their jobs but to ensure that they achieve the desired outcomes. Finally, the review process should not require months and months of review. It should take no more than a week or two to ascertain that the pipeline applicant has the financial wherewithal to live up to its commitments.

Wouldn’t such an arrangement work better for everyone?

Has Rate Freeze Benefited Virginia Customers?

There's no evidence that the electricity rate freeze has hurt Virginians.

Rate freeze —

Are the electric power companies ripping off rate payers under the guise of a rate freeze? Some think so. The electric utility industry came under fire during the 2017 General Assembly session when Sen. Chap Petersen, D-Fairfax, submitted a bill to un-do the freeze in base electric rates enacted in the 2015 session. Although his bill never made it through the General Assembly, Petersen has appealed to Governor Terry McAuliffe to implement it as an amendment.

In an op-ed piece published in the Richmond Times-Dispatch this morning Mark Webb, Dominion’s senior vice president for corporate affairs, argued that the freeze is working as designed and is a good deal for rate payers.

Legislators wanted to protect customers from a potential price hike tied to environmental costs. Since then a Dominion residential customer has paid $1,100 less per year for electricity than those in the Mid-Atlantic.

Were the rates frozen after big increases? Not at all. Dominion residential rates are only about 4 percent higher than they were in 2008. Don’t you wish that was the case with your other household expenses?”

Meanwhile, the reliability of service has improved, Webb writes, and industrial rates have declined 16% over the same period. Virginia’s lower electric rates are significantly lower than Maryland’s and Washington, D.C.’s. Maryland residential customers pay 25% higher rates than Dominion customers, while industrial customers pay 49% more. D.C. residents and industrial customers pay an even bigger premium.

Dominion’s lower rates have been an economic boon for Northern Virginia, Webb says. “No wonder large electric users such as data centers overwhelmingly locate in Virginia instead of D.C. or Maryland.”

(Webb’s op-ed made no mention of the neighboring state of North Carolina, however, where the average electric rate is lower — 10.29 per kilowatt hour in December 2016 compared to 10.72 cents in Virginia.)

Webb then goes one step further, contending that the General Assembly’s re-regulation of electric power energy in 2008 has worked out well for Virginians, too. “Since Virginia’s landmark legislation reregulated utilities a decade ago,” he writes, “electric rates have been remarkably stable and well below the national and regional averages.”

Bacon’s bottom line: I was curious. What are the numbers? How have electricity rates fared compared to national averages (a) since reregulation and (b) since the rate freeze? I checked data compiled by the U.S. Energy Information Administration for “Average Retail Prices for Electricity” for answers.

Between 2008 and 2016, the average residential rate per kilowatt hour for retail customers nationally increased 11.7%, significantly higher than the 4% rate for Dominion customers that Webb cites. So, Dominion has out-performed the national average since reregulation. But rate-freeze critics have not disputed the fact.

A more pertinent question is what has happened to electricity rates since July 2015 when the freeze went into effect. As critics have noted, base rates cover only ongoing operating costs, not the cost of fuel, which is adjusted through fuel adjustment clauses, or the cost of new capital projects, which is incorporated into the rate structure through rate adjustment clauses. In theory, overall rates can climb higher while base rates stay locked in place.

But that has not happened. Between July 2015 and December 2016 (the most recent month available), the average price of electricity in Virginia decreased 8% to 10.72 cents per kilowatt hour. That compares to a 5.9% decline in electric rates nationally between July 2015 and November 2016, according to the Energy Information Administration.

Out-performing the national average since mid-2015 would seem to buttress Dominion’s case, but it still doesn’t end the argument. Former Attorney General Ken Cuccinelli has argued that the rate freeze locks into place hundreds of millions of dollars in excess profits, with the implication that if Virginia electricity rates would be even lower if they hadn’t been frozen. Webb side-stepped that issue in his op-ed piece, and the EIA numbers don’t address it.

Following the Least-Cost Pathway to CO2 Cuts

The least-cost pathway concept acknowledges that as annual electric-sector emissions of CO2 approach zero tons per person, the cost per ton reduced increases.

The least-cost pathway concept acknowledges that as annual electric-sector emissions of CO2 approach zero tons per person, the cost per ton reduced increases. (Image source: IHS Markit)

Global greenhouse gas emissions have increased steadily as China, India and other countries bring new coal-powered electric plants online, but the United States has bucked the trend. In the U.S. electric power sector, CO2 emissions declined 20% between 2007 and 2015.

One might think that California, which is re-restructuring its electric power system to reduce carbon emissions, played a major role in that accomplishment. But it didn’t. In fact, even as the Golden State boosted wind and solar output from 2 percent to 14 percent of in-state electricity production over that period, CO2 emissions held steady. The reason: The share of natural gas-fired generation grew from 50 percent to 60 percent.

Explains IHS Markit, a purveyor of market intelligence and analysis: “This was needed to back up and fill in for intermittent renewables, replace output from prematurely closing nuclear plants, and offset declining hydroelectric generation.”

The economics of CO2 reduction are complex, and not all CO2 reduction strategies are created equal — either in terms of cost or in terms of emissions reduced. As IHS Markit notes in a Wall Street Journal advertorial today, there are more cost-efficient ways to cut greenhouse gases than mandating renewables. “The reductions achieved via [California’s] wind and solar mandates cost 10 times more than the ones achieved through its cap-and-trade programs.”

The idea that cutting greenhouse gas emissions is a compelling national goal is far from universally accepted. Not everyone embraces the more cataclysmic predictions of temperature rise, not everyone believes that an atmosphere richer in CO2 will lead to universally baleful effects, and not everyone agrees with the proposition that cutting CO2 emissions is the best way to respond to a warming climate. But let’s set those reservations aside for a moment and assume that combating global warming and cutting CO2 emissions is a global imperative, and that we’ve all got to do our bit to turn the tide.

IHS Markit employs a concept it calls “the least-cost pathway” to CO2 reduction, which ranks CO2 reduction strategies for the electric power industry by cost-effectiveness — essentially by dollars-per-ton of CO2 saved.

The lowest-cost approach is replacing coal, which emits a large volume of CO2 per unit of electricity generated, with natural gas, which emits about half the volume. That approach is so cost-effective that it has already occurred on a large scale, driven largely by market forces (and Environmental Protection Agency rules that cracked down on emissions of toxic metals from the combustion of coal).

Thanks to the fracking revolution, which has expanded the supply of natural gas and pushed down the price, U.S. electric utilities have shifted dramatically from coal to gas. That’s the reason U.S. CO2 emissions have declined so dramatically. While this approach has not totally run its course, the rate of gas-for-coal substitution is likely to slow significantly, as only the newest, cleanest, most cost-efficient coal plants remain in operation.

Extending the life of aging nuclear power plants is somewhat more expensive, and building new nuclear facilities is significantly more expensive. On the positive side, nukes have zero carbon emissions and they provide a reliable base-load capacity. IHS Markit sums up the pros and cons: “Nuclear power plant extension is cost-effective early on, and new nuclear plants become cost-effective as the curve moves into deeper reduction.”

Energy efficiency is part of the equation, says IHS Markit. However, “encouraging efficiency investments beyond what consumers would do themselves involves increasing costs.”

As for wind and solar, they, too, are part of the solution. “But not as the primary source of generation. … Wind and solar costs are not reaching grid parity when the need to align power output to when consumers want electricity is taken into account. Battery technologies are improving but are still not a cost-effective way to manage variations in electricity demand.”

The comparative economics get murkier when we look into the future. Will natural gas prices increase, and by how much, as the most productive wells are depleted and exports of Liquified Natural Gas soak up excess supply? Will the cost of solar panels and battery technologies continue to decline as in the past, or will the pace of innovation slow? Will the price of building new nuclear plants remain breathtakingly high, or will some combination of new technologies (mini-nukes, anyone?) and relaxation of excessive safety regulations bring down the cost?

As IHS Markit concedes, there is little consensus. Still, the market-intelligence company provides a useful framework for looking at Virginia’s energy future: We should pursue the least-cost pathway to CO2 emissions.

The devil is in the details, of course. We can haggle endlessly over the cost-effectiveness of any given approach. But the idea makes more sense than pre-supposing that any particular approach — coal, gas, extending old nukes, building new nukes, wind, solar, energy conservation — is the way to go. Different energy sources have their own place in the fuel mix as Virginia’s electric power sector moves up the least-cost pathway.

Tracking California’s Grand Experiment with Solar

California solar farm

California is leading the nation’s transition from fossil fuels and nukes to renewable fuels, mostly solar power. The Golden State’s aggressive investment in solar energy has created such a glut of daytime electricity that solar wholesale prices literally drops to zero and such a shortage during the night that real-time prices surge as high as $1,000 per megawatt hour. Regulators and utilities are learning how to cope with these problems through battery storage, grid modernization and energy conservation.

Hopefully, Virginia utilities and regulators are paying close attention as the Old Dominion defines its own approach to renewable energy. On the one hand, by going slowly, Virginia can learn from California’s mistakes and work-arounds. On the other, Virginia’s cautious approach to solar risks allowing other states crack the code first on how to generate reliable, lower-cost and green power, thus converting the price and quality of electricity from a competitive advantage to a disadvantage.

In 2016 the average cost of electricity in Virginia was 8.88 cents per kilowatt hour, according to the U.S. Energy Information Administration. In California, the cost was 14.88 cents per kilowatt hour, 40% higher.

California is spending billions of dollars in giant test project in which the entire state economy is the subject. The great challenge with solar, as oft alluded to in Bacon’s Rebellion, is coping with intermittent nature of generation. Last month, notes the Wall Street Journal, Sempra Energy flipped the switch on a bank of 400,000 lithium-ion batteries installed by Virginia-based AES Corp. The batteries will smooth out power flows in San Diego’s solar-intensive electric grid. Meanwhile, Tesla, Inc., is supplying batteries to a Los Angeles-area network tied together in a microgrid of 100 office buildings and industrial properties. Reports the Journal:

When [Edison International] needs more electricity on its system, the batteries would be able to deliver 360 megawatt hours of extra power to the buildings and the grid, enough to power 20,000 homes for a day, on short notice. At other times, the batteries would help firms hosting the arrays to cut their utility bills.

Clearly, strategies exist for overcoming the variable and daylight-only production of solar panels. The big question is how much the batteries cost. And that tends to be a ticklish subject. As the WSJ noted regarding the Tesla/Edison International project in Los Angeles, “The companies declined to say how much the project would cost.”

Broadly speaking, battery storage has two different uses. One is fine-tuning the electric grid, a function that exploits the ability of batteries to respond instantaneously to micro-fluctuations in voltage and frequency. The other is storing electric power until it is needed at a different time. In this second use, batteries compete with natural-gas peaker plants, which are essentially jet turbines that sit idle until needed. Unlike conventional power plants that ramp up and down slowly, gas peakers and batteries can respond quickly to changes in demand.

Stored power from lithium-ion batteries can do the work of a natural-gas peaker plant at an average cost of between $284 and $581 a megawatt-hour, according to a December report by Lazard Ltd. In contrast, electricity from a new gas peaker plant costs between $155 and $227 a megawatt-hour, according to Lazard.

(By comparison, the average retail price of electricity in Virginia is about $89 per megawatt hour.)

Clearly, lithium-ion batteries are far too expensive at present to use on a large scale in Virginia as a peaking resource. But solar advocates hold out the hope that battery storage will decline in cost. Is that realistic?

The lithium-ion battery chemistry may be reaching the limits of its potential, reports Fortune magazine in an article published yesterday. “The biggest proof may be in the spate of explosions now plaguing smartphone makers from Samsung to Apple, in part thanks to li-ons’ tendency to grow dendrites, metal strands that can cause short circuits.”

John Goodenough, a co-inventor of the lithium-ion battery, claims to have developed a solid-state battery that replaces lithium with sodium, which, in theory, can hold three times more energy, charge quickly, and never explode. Commercialization of the technology is years away, however, warns Fortune. By way of comparison, Lithium ion batteries took a decade to move from the laboratory to the marketplace.

When it comes to reducing CO2 emissions, Californians seem willing to pay any price. That approach will not sell politically in Virginia. But California is more than a Land of Fruits and Nuts. It has some of the most brilliant scientists, engineers and technologists in the world. If green power can be made economically competitive with fossil fuels and nuclear, California will figure it out. We Virginians should not necessarily emulate its example, but we should be paying attention.