Air Pollution Control Equipment Services

The Pathway to Commercializing CCS

Issue 11 and Volume 116.

By Brad Crabtree and Jennifer Christensen

Coal power generation in the U.S. stands at a crossroads. Abundant low-cost natural gas, federal environmental requirements and uncertainty over future regulation of greenhouse gas (GHG) emissions are driving the closure of older, less-efficient coal units and cancellation of planned investments in new coal generation capacity.

The fate of coal generation hinges on successful commercial deployment of carbon capture and storage (CCS) technologies. Fortunately, CCS has progressed much further than commonly acknowledged by the coal and power industry.

While CCS in electric power generation has not yet been demonstrated at commercial scale, it is proven and commercially available today using carbon dioxide (CO2) captured from other industrial processes. There are eight integrated, large-scale CCS projects in operation, with dozens more in development.

Optimism about CCS in the power sector may seem surprising, since challenges are widely reported:

  • Uncertainty over federal GHG policy deters private investment;
  • Low demand and prices for electricity and competition from natural gas makes CCS power projects more costly;
  • Current federal incentives are insufficient;
  • Some environmental groups oppose CCS power projects, not just conventional coal plants; and
  • Recent cancellation of large-scale CCS power projects fuels critics’ false narrative that CCS is unproven.

Fortunately, deployment of CCS in power generation is underway. Integrated gasification-combined cycle (IGCC) power projects by Southern Company’s Mississippi Power (under-construction) and Summit Power (near-construction) will capture 65 and 90 percent of their CO2 emissions, respectively.

Companies are also successfully demonstrating post-combustion CO2 capture at existing coal-fired power plants and driving down costs.

Moreover, the coal and power industry is starting to recognize what the oil industry has understood for years—we already do CCS at scale through CO2-EOR.

CO2-EOR is decades-old, commercially proven technology. The oil industry transports by pipeline and injects 65 million tons of CO2 annually to produce 6 percent of America’s domestic oil. Much more oil could be produced, if more CO2 were available.

Policy-makers increasingly support CO2-EOR as an important energy security, economic and environmental strategy. CO2-EOR creates a revenue-generating CCS business model for power companies through sales of CO2 to the oil industry. It can also fund federal CCS tax credits to the power industry through increased federal revenues from new incremental oil production.

The work of the National Enhanced Oil Recovery Initiative (NEORI), a broad coalition convened by the Great Plains Institute and the Center for Climate and Energy Solutions, shows how CO2-EOR can help cover the cost of CCS deployment in the power sector. NEORI’s analysis demonstrates that modest tax incentives to capture man-made CO2 from lower-cost industrial sources can generate a large stream of new federal tax revenue obtained from increased oil production through EOR. This revenue stream, in turn, can help finance deployment of more costly CO2 capture technology at coal and gas-fired power plants.

Based on NEORI’s work, Senators Kent Conrad (D-ND), Mike Enzi (R-WY) and Jay Rockefeller (D-WV) recently introduced bipartisan legislation to modify the existing 45Q tax credit to help get initial projects across the finish line.

Over the longer-term, NEORI recommends a larger federal CO2-EOR tax credit that would pay for itself within 8 to 10 years. Over 40 years, the tax credit would yield an additional 9 billion barrels of domestic oil, store 4 billion tons of CO2 from power plants and other industrial sources, and generate an estimated $105 billion in net federal revenue — while enabling construction of every serious commercial-scale CCS power project proposed in the U.S. today.

Important progress has been made in proving the technical viability of CO2 capture in power generation, and CO2-EOR offers a business model and revenue stream for federal incentives to accomplish the next stage of widespread commercial deployment of CCS power projects.

It’s time for the coal and power industry as a whole to join other industry, labor and environmental stakeholders in advocating for aggressive commercialization of CCS and for CO2-EOR as the pathway for achieving it.

Authors

Brad Crabtree   Brad Crabtree is policy director and Jennifer Christensen is energy policy specialist at the Great Plains Institute. They help staff the National Enhanced Oil Recovery Initiative, in addition to other regional and national CCS policy work.   Jennifer Christensen

NSPS: A Game Changer

alt   By John S. Lyons, Director, Kentucky Department of Environmental Protection

We’ve all seen them or heard an environmental regulator mindlessly spit them out during a mundane presentation. The lay person needs subtitles to understand their meaning. CSAPR, CAIR, FIP, NAAQS, MATS, GHG, NSPS – the list goes on and on. This alphabet soup of acronyms has been at the center of an increasingly polarized debate about environmental regulations and programs. What does it all mean for the regulated community, and why has the conversation become so contentious?

No other industry has been more heavily regulated than electric generation, and from a pollution standpoint, rightfully so. Power plants emit millions of tons of pollutants every year that have been clinically proven to cause detrimental health effects and even premature death. Regulations limiting emissions of pollutants such as sulfur dioxide and nitrogen oxides have resulted in a profound improvement in our health and air quality.

For example, cap and trade programs addressing sulfur and nitrogen oxide emissions have been very successful in reducing emissions that cause acid rain and smog problems. In Kentukcy, concentrations of sulfur dioxide in the ambient air are down 81 percent since 1981, and 52 percent for nitrogen oxide in the same timeframe. Air pollution control technology, driven by federal regulations under the Clean Air Act, has made this possible. However, the latest round of regulations, fraught with ongoing litigation, has taken a different direction than previous programs.

To understand why, one must first have a clear grasp of how the Clean Air Act (CAA) and corresponding regulations work in concert to address “impaired” air quality. It starts with periodic reviews of existing National Ambient Air Quality Standards (NAAQS) that cover six specific pollutants: sulfur dioxide, nitrogen oxide, particulate matter, carbon monoxide, ozone and lead. These are health-based standards and are required to be revisited by EPA every five years in accordance with the Act. A review of a NAAQS most often results in a proposal by EPA to tighten the standard.

Once a standard has been set, state and local air quality agencies are responsible for reviewing their monitoring data and determining if an exceedance of the new standard exists. Generally, three years of data are considered when making this determination and if the standard is being exceeded, the state must take steps to correct the problem. However, this is where it gets tricky for many states.

State environmental agencies are not usually permitted by their legislative bodies to develop regulations that are more stringent than federal regulations. Knowing this, and in an attempt to consistently regulate large sources of pollutants, the EPA develops federal programs that states can and, in many instances, must adopt to address their impaired air quality.

So, what makes the current landscape of protection of air quality so contentious compared to the previous 40 years? Certainly, there has always been some amount of partisan politics in Congress. There has always been some reluctance by the industry to pass on the cost of environmental controls to their rate payers. And, there have always been the grassroots environmental groups to balance the scale. What’s different?

Greenhouse gases. Yes, GHGs.

EPA recently proposed a New Source Performance Standard to regulate GHGs at all new fossil fuel-fired electric generating units. While not a NAAQS, this standard is every bit as impactful, if not more so, than the health-based standards that have been the foundation for the CAA.

In essence, the proposed rule sets a standard that only a natural gas-fired combined cycle turbine can achieve. While EPA left the door open for new coal-fired generation by including an option for a 30-year average of the standard, this could only be achieved by Carbon Capture Utilization and Storage. No one is expecting CCUS to be a commercially available, let alone affordable, technology in the next 10 years. As a result, no entity would ever risk the capital to build a coal-fired power plant under this scenario. In short, EPA’s proposed GHG standard essentially slams the door on any new development of coal-fired power plants. Coming from a state that gets 95 percent of its electricity from coal, you can bet there is a lot at stake.

Gina McCarthy, Assistant Administrator of EPA’s Office of Air and Radiation, insists EPA is not picking winners and losers with this standard. Most folks in Kentucky, as well as several other states, feel otherwise. Many elected officials think it is not appropriate to set energy policy via regulation. EPA says it is only carrying out its mission and doing the job that the Supreme Court said it had the authority to do. Whichever side you fall on, make no mistake: This is big news in the world of air quality regulation.

While it’s too soon to tell what the ultimate impact of the NSPS will be, air quality regulations have become a battleground issue in Congress.


Best Practices in Long-Term Facilities Capital Planning

By Chuck Hodian

Energy and utility companies are among the most vital facilities in society, and the mission-critical nature of the equipment and requirements of operating time make them extremely expensive to operate and maintain. Given today’s economy, utility companies must look for approaches and strategies to ensure that efficiencies within their facilities are found quickly and that costly emergency repairs and downtime that affects the delivery of critical services are avoided.

Developing an effective long-term capital plan requires energy and utility companies to maintain a comprehensive understanding of the entire facility portfolio, determine what improvements are required, prioritize those improvements to align with the overall goals of the organization, and finally ensure that the budget is spent as planned.

It is crucial for organizations to be proactive about the investments they need to make in their facilities, by understanding the composition of their building portfolio, the existing physical condition of their facilities, the required remediations and their costs and the prioritization of facilities investments.

Accurate data is crucial to capital planning. Without detailed information regarding facility condition and lifecycle stage, planners cannot sufficiently defend budgets. It is equally important to understand the best method for an organization to collect these data in order to act accordingly. A Facility Condition Assessment (FCA) is the process of collecting detailed data on facility condition and deficiencies, generally with walk-through inspections by qualified professionals (mechanical, electrical and architectural engineers) to collect this baseline data. These teams survey facilities in detail using consistent best practice methodologies.

Another option for data collection is facility self-assessment that employs a consistent, repeatable process for internal staff. Leveraging existing facility resources to quickly assets of all types and portfolios of all sizes, organizations can greatly enhance the management of geographically dispersed facilities. The self-assessment process should be rapid and cost-effective, resulting in data that can identify “hot spots” within the portfolio that require a more detailed professional condition assessment, and help develop quick budgetary estimates. A good facility self-assessment also maintains data captured in previous assessments to ensure that strategic decisions are based on factual information.

One of the benefits of gathering accurate facility data is that the true facility condition, both by individual asset and across the portfolio, becomes clear. This data also enables facility staff to run a metric to analyze the effect of investing in facility improvements. Industry-wide, this benchmark is known as the Facility Condition Index (FCI). The FCI is the ratio of deferred maintenance or problem dollars to replacement dollars and provides a straightforward comparison of an organization’s key real estate assets. Organizations can use the FCI to run “what-if” scenarios that demonstrate the impact of various funding levels on facility condition, enabling them to arrive at realistic, optimal multi-year capital plans.

Prioritization plays a major role in successfully reducing deferred maintenance and avoiding unexpected spikes in required funding over time. Statistical ranking methods, such as pair-wise comparisons, can be used to facilitate the process, effectively tying requirements to organizational priorities. After each capital request is enumerated individually, all requests for a funding source can be ranked by score.

When companies have a basis for making informed decisions about project prioritization and capital budget allocation, they are less vulnerable to emergency failures. Emergency repair projects typically result in hefty premiums for labor during non-standard work hours, rushed shipments, and unplanned, but necessary one-off purchases.

With increased demand for transparency of information, employees are increasingly held accountable for their decisions. Facility managers and capital planners must find ways to automate and streamline all workflow that is associated with the collection, storage and reporting of facilities and infrastructure condition information. Organizations without consistent assessment methodologies and centralized databases are at greater risk for non-compliance, higher insurance premiums, and overall exposure to liability.

By following best practices in strategic facilities capital planning and management, utility companies can reduce risk, provide facilities that are less expensive to operate, and better serve the overall organizational mission.

Author

Chuck Hodian   Chuck Hodian is vice president at VFA, Inc., a provider of end-to-end solutions for facilities capital planning and management. He has more than 20 years of sales and senior management experience in software and business solutions.

A Particulate Mess: The Proposed NAAQS Pm2.5

By Lindsay Morris, Associate Editor

In response to a court order under the Clean Air Act, in June the U.S. Environmental Protection Agency (EPA) proposed updates to its national air quality standards for fine particle pollution, including soot (known as Pm2.5). The proposed standard has the potential to create a tangled, regulatory mess as power producers sort through the remnants of the Cross State Air Pollution Rule (CSAPR) and consequently make both gas and coal compliance more challenging.

EPA has proposed to limit Pm2.5 to a level within a range of 13 micrograms per cubic meter to 12 micrograms per cubic meter. The current annual standard is 15 micrograms per cubic meter. EPA has said the proposal has no effect on the existing daily standard for fine particles or the existing daily standard for coarse particles (PM10), both of which would remain unchanged. EPA plans to issue the final standards by Dec.14, 2012 and expects affected counties to achieve attainment by 2020.

Reductions in both PM10 and Pm2.5 over the past couple decades have been dramatic. PM10 saw a reduction of 37 percent nationwide from 1990 to 2010, and Pm2.5 was cut by 29 percent from 2000 to 2010, according to data from the EPA.

In fact, not just PM, but every major emission type, including carbon, nitrogen dioxide and sulfur dioxide, has encountered impressive decreases. But despite major efforts by power producers to limit emissions, EPA has increased its number of non-attainment areas as a result of the agency redefining what is “healthy air.” So while the air is getting cleaner, the standards are also becoming more stringent.

Part of the emissions squeeze, so to speak, came in 1997 when EPA decided to add Pm2.5 as a National Ambient Air Quality Standards (NAAQS) pollutant. EPA is required under the Clean Air Act to re-examine the standards once every five years.

In February, the American Lung Association and the National Parks Conservation Association sued EPA for not completing the review of the standards within five years – by October 2011. The states of California, Connecticut, Delaware, Maryland, Massachusetts, New Mexico, New York, Oregon, Rhode Island, Vermont and Washington also filed a separate suit. Obviously, EPA had no choice but to review the standards. However, proposing to enforce relatively stricter standards on Pm2.5 is likely in part an effort to appease the opposing groups.

Controlling fine particle emissions can be particularly challenging, as Pm2.5 can be formed both directly and indirectly. The pollutant can be emitted directly from a source, but it can also be formed miles away from a source when pollutants like SO2 and NOx chemically interact in the atmosphere.

The proposed soot rule may not have a huge impact on coal-fired power plants since those facilities are already facing stringent compliance under other regulations like the Mercury and Air Toxics Standard (MATS). However, the proposed rule could have a more significant impact on gas power plants, since gas turbines have less control on particulate emissions, and their NOx emissions are frequently low enough that they may not have many pollution control devices already installed.

EPA says that depending on the final level of the standard, estimated benefits will range from $88 million a year, with estimated costs of implementation as low as $2.9 million, to $5.9 billion in annual benefits with a cost of $69 million.

“It is not a significant cost rule because of all of the reductions that have already been achieved,” said Gina McCarthy, assistant administrator for EPA’s Office of Air and Radiation.

Implementation of actual PM limitations could be a lengthy process, however, since the EPA must reevaluate PM limitations under CSAPR, which was rejected by a federal court in August. Because of CSAPR and MATS, most areas are already in compliance, McCarthy said.”That’s why 99 percent of U.S. counties are already on a path to meet these standards.”

However, since CSAPR has now been replaced by its predecessor, the Clean Air Interstate Rule, the proposed Pm2.5 NAAQS and CAIR being reinstated could cause some compliance overlap. Once the Pm2.5 NAAQS is final, EPA will have to reexamine CSAPR allowances in 2013 to see if a reallocation is needed. That reallocation could impact coal and gas-fired facilities two to three years after the rule is final, or in the 2015/2016 timeframe.

However, if CSAPR is totally rejected by the D.C. Court (EPA filed for an en banc rehearing of CSAPR on Oct. 5), it could take EPA two to three years to re-propose a new transport rule – a year to finalize and additional years to get through the inevitable legal challenge. Reconfiguring CSAPR could subsequently cause implementation of a new NAAQS Pm2.5 to be postponed until 2017 or later.