A recent federal rule on coal combustion residuals (CCR) was widely seen as a win for electric cooperatives. It designates CCRs as non-hazardous waste and encourages their continued beneficial use.
Unfortunately, the rule also makes the management and disposal of CCRs that are not used beneficially more complicated, more uncertain, and more costly.
Issued by the Environmental Protection Agency (EPA) in October 2015, the rule governs the handling of power plant coal byproducts, including fly ash, bottom ash, boiler slag, and flue gas desulfurization (FGD) materials.
Coal-fired power plants in the United States produced nearly 130 million tons of CCRs in 2014, the most recent year for which data is available from the American Coal Ash Association. NRECA’s Strategic Analysis division estimates co-op generation facilities accounted for roughly 9 to 10 percent of those CCRs, or about 12 to 13 million tons. Of the 130 million tons produced that year, more than 62 million tons, or 48 percent, were reused.
The EPA rule lays out extremely tight deadlines for monitoring existing CCR disposal units—surface impoundments and landfills—as well as the agency’s requirements for closing such units and building new ones.
The rule is “self-implementing,” which means it will be enforced by lawsuits brought by the public or state and local governments rather than states issuing permits. The rule does not regulate CCRs processed for beneficial use, such as road paving or building materials, CCRs disposed in municipal solid waste landfills permitted to accept them, or residuals placed in underground or surface coal mines. Disposal in coal mines, however, will be the subject of a future rule from the U.S. Department of the Interior.
G&Ts that operate coal-fired plants must meet location and unit operational standards, install a system of groundwater monitoring wells around their CCR impoundments and landfills, and specify how those wells will be sampled and analyzed. The rule also sets aggressive deadlines, some of which have already come and gone, for creating dedicated websites for posting compliance information, including groundwater monitoring results.
In addition, G&Ts must assess the structural integrity and safety of their CCR impoundments, and they will have to meet the rule’s criteria for closing disposal units as well as monitoring them after they’ve been closed.
The costs of complying with these new requirements will vary widely among G&Ts and among individual power plants, but they could rise to millions of dollars in some cases. And the “self-implementing” enforcement mechanism could lead to costly legal actions.
Another EPA rule also complicates G&T compliance plans. The Effluent Limitations Guidelines (ELG) rule, which took effect early this year, governs discharges of wastewater from power plants. The rule prohibits the discharge of any water that transports bottom ash or fly ash and imposes stringent limits on discharges of FGD wastewater. Converting to dry ash management will, in many cases, trigger closure of current impoundments.
Many plants are subject to both rules and are working to develop compliance plans and schedules that reflect both.
Taken together, the rules have raised numerous concerns among G&T environmental and compliance managers. “We’re in survival mode,” one manager said. “But we don’t have any plans to shut down now.”
G&T managers say the cost of compliance is an overriding worry, but there are other concerns, including:
Groundwater monitoring wells. A few G&Ts do not have groundwater monitoring systems in place around their impoundments or landfills, but even those that do will likely have to augment or replace them to comply with the new rule. “For all co-ops, the clock is ticking,” the report states. G&Ts will have to report eight analyzed samples from aquifers up- and downstream of the disposal site by October 2017.
Existing versus new wells. Decades of experience and data from existing monitoring wells may not be good enough for the EPA under its new rules, G&T environmental officials say. Arizona Electric Power Cooperative (AEPCO), for instance, installed monitoring wells 20 years ago. EPA’s new rule, however, requires utilities to determine the direction of groundwater flow, which AEPCO’s experts say can change over time. The G&T argues that this “cookie-cutter rule” ignores unique characteristics of each disposal site. North Dakota-based Basin Electric Power Cooperative has systems in place around plants in North Dakota and Wyoming that met the states’ permitting requirements. But the wells may be farther away from the disposal sites than EPA’s rule allows. “Even though we have 30 years of data, it may not be good enough to meet the rule’s requirements,” a Basin official says.
Another G&T with no monitoring wells at its two CCR impoundments is spending $100,000 to install four to six exploratory wells, and it expects to spend as much as $1.2 million more, depending on the findings from those first wells.
Existing sites that don’t meet new requirements. AEPCO’s impoundments use two liners of high-density polyethylene on either side of an 8-in. layer of clay, but EPA’s final rule specifies a 2-ft. layer of low-permeability clay. The rule does allow continued use of such impoundments, however, if they comply with groundwater monitoring, stability, and seismic requirements. Another G&T has several impoundments, none of which meets the liner requirements. An official at that G&T expects to meet the rule’s stability and seismic provisions this year, “but if we find a problem with groundwater contamination at an impoundment, we will have to close it.”
Closure or retrofitting. Ash ponds and other surface impoundments that fail to meet the rule’s design, siting, and structural requirements must either close or undergo retrofitting.
Ash pile containerization. Some G&Ts store CCRs in piles prior to disposal or beneficial use, and one G&T processes fly ash and scrubber sludge by mixing and piling them until they are transported to a disposal site. But under the new rule, coal ash piles are considered landfills unless they’re “containerized,” which could require a concrete, asphalt, or similar impervious base. Leachates and runoff would have to be collected and fugitive dust-control measures taken. The rule does not require the pile to be placed in a tank or containment structure. “It would take three-quarters of a million [dollars] to containerize the pile,” one G&T engineering manager said.
“Self-implementation.” Because the rule will be enforced by state and citizen lawsuits, many of the G&Ts contacted for this report worried that implementation could become inconsistent, litigious, and costly. “Such lawsuits could result in frivolous and costly legal disputes in federal district courts, where the resulting interpretations and penalties could vary significantly,” Lisa Johnson, CEO at Seminole Electric Cooperative in Florida, warned a congressional committee in January 2015. A Burns & McDonnell environmental consultant noted, “The decision of a judge hearing a case in Oklahoma may not be consistent with the decision of a judge in Ohio.”
Other G&Ts also raised concerns about groups using the rule to haul utilities into court. Corn Belt Power Cooperative, an Iowa G&T, has shifted to natural gas and no longer burns coal. But Mike Thatcher, vice president of generation, echoed the view of many G&T officials when considering “self-implementation.” “We would rather deal with regulators than with folks who may have an agenda,” he said.
State versus federal rules. Overlapping, duplicative, and potentially conflicting requirements under what G&Ts see as a “dual regulatory approach” also emerge as a major co-op concern. North Carolina “compels the ultimate closure of all surface impoundments,” while in Arizona, AEPCO “must do a lot of redundant work to meet the federal regulation, while state agencies have already set rigorous permitting requirements. ... It is once again spending hundreds of thousands of dollars for engineering calculations and new monitoring wells that essentially replicate the existing system.”
Basin Electric reported that North Dakota and Wyoming, where the G&T operates coal plants, are working to harmonize their state groundwater monitoring rules with the EPA’s final rule. But that effort could take years, according to an official at the G&T, and in the meantime, Basin will end up with two networks of monitoring wells. “We’ll have two sets of groundwater monitoring data because the state and federal requirements governing a well’s distance from an impoundment are different.”
“Hazardous” CCRs. NRECA and its G&T members welcomed the EPA’s decision in 2014 to designate coal ash as “non-hazardous waste.” But less than two years later, the agency suggested in the preamble to its final CCR rule that it may reconsider that move. Such a change, according to one top Tennessee Valley Authority manager, “would seriously impact our ability to market CCR products for beneficial uses.” The same is true for AEPCO, which sells more than 90 percent of its fly ash as an additive to concrete.
Uncertainty about using coal mines for CCR disposal. While last year’s final rule explicitly does not apply to CCRs placed in active or abandoned underground or surface coal mines, the EPA said it planned to work with the Department of the Interior to make sure such disposal “is adequately controlled.” That opened a worrisome question for some G&Ts. “We have no idea what that rule might be,” one engineering manager says. “This is a black-hole issue that could significantly impact our operations.”
The timeline. The welter of rushed deadlines is “problematic,” a Basin Electric official says. One in particular, coming up in October, gives G&Ts pause because that’s when they’ll have to demonstrate that their impoundments and landfills meet structural stability and safety requirements. If tests undertaken since the rule took effect last fall show the need for changes, G&Ts may simply not have enough time to get the work done. Permitting times alone can exceed six months, AEPCO has found, making it impossible to meet the deadline for bidding and completing the work. “You have very little time to do something,” another G&T’s environmental director said.
G&Ts have considered a number of approaches to meeting the CCR rule.
For instance, many G&Ts already market some of their CCRs, and some are able to sell nearly all their fly ash for use in concrete or stabilizing waste from other industrial processes. Markets, coal type, and economic conditions can limit this option, however, and that preamble in last year’s final rule suggesting another look at the “non-hazardous” designation for coal ash increases the uncertainty.
Transporting CCRs to a new offsite landfill may also solve the immediate compliance problem. But this option comes at a price: Depending on the type of coal used, according to two NRECA analysts, the cost of this approach could reach more than $3 per MWh.
Closing inactive disposal sites, building new ones, switching to “dry handling” of ash, and exploring additional ways to turn all CCRs into marketable byproducts are other potential compliance options.
This article is adapted from G&Ts Face Major Cost and Time Challenges in CCR Rule Compliance, a TechSurveillance report released in April 2016 by the Generation, Emissions, & Carbon Dioxide Work Group in NRECA’s Business & Technology Strategies unit. The full report was written by Alice Clamp, a technology writer who has more than two decades of energy and utility experience.
Editor’s note: Many sources in this report requested anonymity to speak freely about the issue.