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US EPA Rule Unanimously Affirmed by DC Circuit Court: Next Up: CSAPR

Fri, 13 Jul 2012 10:09:00 -0600

As most of you likely know, the EPA CO2 rule for stationary sources was unanimously affirmed last month by the DC Circuit Court. The rule is more or less an extension of the Clean Air Act's New Source Review (NSR) provisions to cover CO2 in addition to SO2 and NOx. As with the traditional "criteria pollutants," for existing plants there is a threshold beyond which any annual increase in annual emissions triggers the NSR litigation process. And, as with SO2 and NOx, this threshold is defined in terms of tons per year, as opposed to the rate of emissions per MWh of generation. So the same so-called "perverse incentives" apply: making improvements to either capacity or capacity factor can trigger NSR litigation even where the rate of emissions per electricity generated remains constant or even improves.

What this means is that anything which causes an increase in annual CO2 of 25 tons per year can trigger costly time-consuming litigation and penalties. To put the magnitude in perspective, for a 600 MW coal-fired boiler, this threshold would be reached with merely a 1.5% increase in output or degradation in heat rate. Ironically, many retrofits required to meet new and emerging NOx and SO2 limits -- such as scrubbers, SCRs, or low-NOx burners -- extract at least this large a heat rate penalty.

While these regulations can be considered a prime example of the perverse incentives that arise as a consequence of the complicated regulations required by the Clean Air Act, the EPA acknowledges in implementing these regulations that carbon capture and sequestration is costly and commercially unproven, and that there are very limited current options for reducing CO2.

Accordingly, the remedies considered by the EPA as Best Available Control Technology (BACT) for coal-fired boilers are limited to commercially available technologies that are known to improve efficiency, i.e. reduce heat rate. The EPA Technical Document describing BACT alternatives includes turbine upgrades, economizer modifications, combustion optimization and sootblower optimization. Ironically, hardware modifications such as turbine upgrades or boiler modifications also have the effect of increasing capacity, which could trigger NSR litigation.

While there is as yet no case history for NSR as applied to CO2, such upgrades and the associated increased in capacity and annual output have triggered NSR litigation for SO2 and NOx across a wide variety of coal-fired plants over the last 15 years. Only time will tell how this plays out for CO2, but suffice to say any cost-effective alternatives for improving efficiency and/or mitigating the heat rate degradation associated with emissions control retrofits can be seen as a prudent investment.

In closing, it is worth noting the DC Circuit Court judges who issued this ruling and referred to the CO2 rule as "unambiguously consistent with the requirements of the Clean Air Act" are the same three judges reviewing the CSAPR regulations for NOx and SO2, for which a ruling is expected any day now. As I have stated in earlier blogs, most of the power industry people I talk with believe that the order will keep CSAPR largely intact, but move back the implementation deadline from the original January 2012 date to 2013, whether at the onset of the calendar year or in June, when the CSAPR Ozone Season begins.

While many in the industry remain concerned about meeting these deadlines despite their being deferred by 12-18 months from the originally issued rule, most I talk with would nonetheless prefer regulatory certainty to the guessing game that has prevailed since the original rule was stayed at the 11th hour within days of the original implementation date. All I can say is stay tuned...

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Improved Reliability and Commercial Availability Through ProcessLink?

Tue, 05 Jun 2012 14:54:00 -0600

As a NeuCo founder who was part of our company's childhood as a combustion optimization provider focused largely on NOx reduction, it’s gratifying to see our technology offering expand to encompass improving the full spectrum of power generation processes affecting not only emissions, but efficiency and availability as well. And, as a former energy economist, it excites me to be able to help our customers improve their reliability and availability in particular, due to the key role they play in determining plant and corporate financial performance.

I generally try to focus my blogs on industry trends and regulatory developments, as opposed to our technology per se. However, with the current financial challenges facing our industry, combined with the fruits of NeuCo's intensive development effort in recent years suggest that it might be useful to summarize the many varied ways in which our technology can help improve availability.

Types of Availability Improvement
Broadly speaking, there are two fundamental ways in which ProcessLink® optimization technology contributes to improved reliability and availability. First, is through optimizing operations for coal-fired boilers. These availability improvements come in the form of reduced water wall erosion and corrosion and associated tube leaks, slagging and out-of-control process excursions through integrated optimal management of the highly interrelated processes of boiler stoichiometry, cleanliness, heat transfer and temperature control.

Second, comes from early detection of anomalous data indicating potential equipment health issues and quicker, more accurate identification of the root causes, criticality and actions needed to remedy the underlying problem. These can be obtained from all fossil-fired generation, regardless of fuel-source or configuration. I will address both, but let's first focus on integrated boiler optimization for coal-fired boilers.

Availability and Boiler Optimization
NeuCo’s closed loop boiler optimization directly impacts generating unit availability.   Our closed loop optimizers reduce water wall erosion, corrosion, and thermal stress which can cause tube ruptures (which are responsible for half of the generation industry's forced outages), lost megawatts and foregone revenue.

Erosion is the physical wear that occurs as the result of either hot gasses or boiler cleaning media: steam, compressed air or water. Our comprehensive boiler optimization solution BoilerOpt® (combining the functions of both CombustionOpt® and SootOpt®) helps to avoid erosion through fewer cleaning actions. Water wall erosion is a major cause of tube ruptures. Where water is used as a cleaning medium, BoilerOpt helps avoid the water wall and boiler tube cracks that occur through thermal stress, which compromises the strength and integrity of the metal and contributes to tube ruptures.

Corrosion refers to a chemical process that compromises the structural integrity of steel used in the water wall and embedded tubes. It primarily occurs as a result of the reducing atmosphere from low-NOx (i.e. deeply staged) firing. In this situation, oxygen that would normally bond with iron is in such short supply (because it is used in the formation of CO) that iron monoxide (FEO) forms instead, rapidly accelerating water wall wastage and tube ruptures. This process drives the same type of unpredictable forced outages as the erosion process described earlier.

BoilerOpt helps avoid reducing atmospheres though better mixing of fuel and air and less CO formation. Its model predictive control (MPC) technology provides fundamentally better ability to maintain and achieve O2 and CO set points with controls effecting overall boiler oxygen levels, even during times of rapid load changes. Neural network models are able to effectively resolve the cause-effect relationships between individual damper movements and a single measurement of stack CO, which is why it has been proven to not only reduce NOx and improve boiler efficiency but also avoid local pockets of substoichiometric firing conditions. The combined effect helps avoid the oxygen-deficient conditions and reducing atmospheres that cause water wall corrosion, while simultaneously reducing NOx and improving boiler efficiency.   Optimization also helps avoid operator-induced swings (due primarily to under and over-compensation) in load, emissions, temperatures, fan and mill loading and other key operating parameters resulting in fewer outages and an increased capacity factor.

In summary, BoilerOpt consistently reduces blowing operations by 20-35% while improving boiler efficiency by 1% - 2%, reducing NOx by 5% - 20% and maintaining CO at set levels. Comprehensive boiler optimization addresses combustion and heat transfer processes in an integrated manner by not only substantially reducing tube leaks, but also reducing de-rates and outages due to fouling, slagging, emissions excursions and overtaxing boiler equipment such fans and pulverizers.

Equipment Health and Availability
As we know, operating generating units creates complex, inter-dependent systems for moving air, grinding coal, pumping water, extracting energy from steam and converting motion into electricity. These systems are based on large-scale mostly rotating equipment with extreme duty cycles, critical needs for lubrication and cooling and multiple failure modes. Such equipment includes fans, pumps, mills (for pulverized coal), turbines and generators.

While a typical plant has thousands of real-time data points monitoring the performance and health of its equipment, noticing anomalous patterns in this sea of data is akin to finding a needle in a haystack. And while there are dedicated systems for monitoring individual signals, such as bearing vibration or metal temperatures, they focus only on the specific measured data itself, rather than the many, fast moving, relevant interactions that complex processes create, which makes it difficult to distinguish anomalies indicating actual problems from normal degradation and changes in operating conditions (load, ambient conditions, etc.).

Setting alarm thresholds based only on the measured signals themselves thus imposes a harsh tradeoff: tight thresholds result in false positive and "alarm flooding," while relaxing them results in overlooking important but subtle changes that indicate real problems with equipment health and reliability.

Anomaly Detaction and Predictive Maintenance for Improving Availability
MaintenanceOpt® compares measured signals with model predictions in the context of system interactions to detect reliability, capacity and efficiency-related anomalies with much greater accuracy, scope and effectiveness than traditional condition monitoring systems. It also provides the information necessary to diagnose which anomalies point to real problems, to identify the causes of the problems and to prioritize the urgency of resolving them. MaintenanceOpt is continually scanning for process and equipment health anomalies minimizing the likelihood of being blindsided by unpleasant surprises.

Working as a 24x7 ever-watchful partner, MaintenanceOpt saves time by going beyond alerts to help filter false alarms, identify root causes and corrective actions and prioritize the urgency of resolving problems. MaintenanceOpt uses neural network technology to constantly search for gaps between actual and expected behavior across a broad range of process and equipment health variables. Once these anomalies are detected, MaintenanceOpt’s heuristics knowledgebase helps to determine whether the problems are real, and if so, their most likely causes, the order in which they should be addressed based on criticality and cost impacts and the actions needed to resolve them.

MaintenanceOpt's unique model-based predictive alerting functionality complements computerized maintenance management systems (CMMS) for planning, scheduling and tracking maintenance activities resulting from those identified anomalies. MaintenanceOpt enriches these systems by helping to more quickly and effectively identify anomalies with equipment health implications; and also help determine the cause, criticality and remediation of the underlying problems. Recently, we’ve been working more closely to integrate MaintenanceOpt with CMMS systems, a development which I’m very excited about but will have to save it for a future posting.

Let me conclude by reiterating my excitement at NeuCo having developed, proven, and commercialized a full complement of products aimed squarely at improving reliability and availability, the most fundamental determinant of plant financial performance. The timeliness of these products with respect to current industry challenges is two-fold. Clearly, the combination of stringent new emissions regulations and low natural gas prices means that improved availability will play a crucial role in determining the continued financial viability of coal-fired generation assets. At the same time, MaintenanceOpt can also help with reliability issues imposed by natural gas-fired combustion turbines and combined cycle boiler plants, which by dint of emissions regulations and low gas prices are playing an increasingly important role in meeting our country's electricity needs.

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Update on EPA Air Emissions Rule-Makings for Fossil Power Generation

Thu, 15 Mar 2012 12:23:00 -0600

It's been a few weeks since I last blogged, as the day job can be kind of a hindrance, so let me bring you up to speed on the three most significant EPA rule makings as they affect fossil power generation. I've addressed the status and implications of each rule, in decreasing order of certainty, with respect to what is currently known.

The Utility MACT Rule
The Utility MACT rule sets maximum achievable control technology (MACT) standards for coal and oil generating stations for removing mercury, acid gasses and a variety of toxic metals from the flue gases for coal- and oil-fired utility boilers. The EPA projects that the Rule’s annual incremental compliances cost will be $9.6 billion. This rule-making has been finalized and is largely viewed to be above legal challenge. The rule was first issued on March 16th, 2011 and finalized on December 16th, 2011. The MACT rule complies with a Consent Decree of the D.C. Court of Appeals that requires the EPA to fulfill the Clean Air Act (CAA) regarding hazardous air pollution from power plants. The Clean Air Act required the EPA to determine whether such regulation is “appropriate and necessary,” which the EPA did in 2000.

Industry efforts failed to extend the deadline for compliance when a federal court denied a requested one year postponement. Congress discussed and even voted bills that would delay the rule, but neither passed both houses and faced Presidential vetoes. Additionally, Section 307(b)(1) of the Clean Air Act stated that “any petitions seeking either administrative or judicial review of a final EPA rule must be filed within 60 days after the rule is published in Federal Register.” We are well past that phase now.

As described in my recent blog, some changes made during the public review process were embodied in the final rule. For example, filterable particulate matter can be used as a surrogate for non-mercury HAP metals, which contributes to substantially fewer scrubbers being installed on coal-fired units. In an important late addition required by MACT, "neural network" optimization systems now qualify for the "optimizing of NOx and CO". Boilers benefitting from such optimization can delay participation in the EPA best practices boiler operations evaluations by one year and reduce the frequency for subsequent evaluations from every 3 years to every 4 years. The EPA’s explicit recognition on the value of optimization not only reduces a painful regulatory burden by 25%; but it also signals that the EPA views closed-loop optimization as part and parcel of the best practices boiler operations as they pertain to minimizing non-measurable HAPS (i.e. fiurin and dioxin).

The CSAPR Rule
Now let's move on to a rule-making a bit more up in the air, so to speak. As I'm sure you’re aware, the US Court of Appeals for the D.C. Circuit issued a ruling on December 30th, 2011 to stay the Cross-State Air Pollution Rule (CSAPR), which had scheduled to take effect on January 1st, 2012. The rule requires 28 Eastern and Midwestern states to reduce SO2 and NOx emissions, accompanied by a supplemental rule finalized in December mandating five states to make summertime NOx reductions as part of CSAPR ozone season control program.

The D.C. Court appears to be keeping its promise of an aggressive schedule for addressing its judicial stay of CSAPR. The consolidated plaintiffs (Homer City, et. al) submitted their collective written arguments last month and the EPA submitted its brief in defense Oral arguments on March 13th, with a court ruling expected shortly thereafter. Here's a high-level summary of the EPA arguments:

•    The Transport Rule’s approach to “significant contribution” is consistent with CAAA and this court’s precedent
•    Cost considerations are a proper part of the Transport Rule’s “significant contribution” approach
•    EPA’s approach does not result in “over-control” of emissions from upwind states
•    Petitioners’ claim that states were not required to submit SIPs to meet their statutory obligation to address interstate transport is not properly before the court and is meritless
•    EPA’s approval of CAIR SIPs does not eliminate its authority to issue the Transport Rule FIPs
•    EPA reasonably addressed transmission constraints in establishing state budgets and allocating allowances to individual sources
•    EPA was required to set expeditious compliance aligned with NAAQS attainment deadlines
•    The emissions reductions required for 2012 and 2014 are practicable

The content and forcefulness of these arguments suggests that CSAPR’s originally published and modified regulations are consistent with the court's original reasons for over-turning CAIR with the requirements of the CAA and CAAA statues. Virtually everyone I’ve spoken to in the power industry expects and is preparing for CSAPR to move forward expeditiously later this year, in much the same fashion as it was originally issued.

GHG Standards for Existing Plants
And finally, the most speculative of all three, the long-awaited EPA promulgation of efficiency standards for existing plants for green house gas reduction. These regulations are EPA's response to the US Supreme Court's ruling that carbon dioxide emissions is a threat to public health and builds upon the court-mandated EPA endangerment finding. That finding has enormous implications, since it requires the EPA to regulate CO2 emissions under the CAA.

Though the Supreme Court has clarified that greenhouse gases (GHGs) were pollutants within the definition of the statute in Massachusetts v. EPA (2007), it did not specify which regulatory tools the agency must use for which sources of GHGs. States and environmental groups moved to resolve this uncertainty by suing the EPA in 2008, seeking required performance standards for GHG emissions from fossil fuel electric generating units (EGUs) and refineries. EPA settled the suit in December 2010 by agreeing to implement performance standards for new and existing generating units and refineries. The EPA stated that these regulations would be finalized by 2012 stating "it remains unclear exactly what that standard might be, whether a limit for greenhouse gas emissions per kilowatt-hour of electricity produced, pollution per amount of fuel burned, or a requirement for all coal-burning power plants to achieve a certain level of efficiency.”

The net result of all the legal wrangling is that GHGs must be regulated in the same manner as NOx and SO2 under the CAA. Accordingly, we can look toward the CAA to understand the applicable approaches subject to existing law. Under Section 111(d) of the statute, the EPA sets guidelines for states’ regulation of existing sources, i.e. those that are not new or being modified. The EPA is directed to identify the “best system of emissions reduction” for each pollutant and use that to set the standard or guideline. Emitters are not required to use the specific technology identified by EPA, but they must achieve similar emissions performance. In other words, the regulations are performance standards, as opposed to command-and-control technology mandates.

Consistent with this approach, the EPA published a technical document in October 2010 titled "Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal-Fired Electric Generating Units." In it, the EPA concludes that capture and sequestration are not commercially viable, but outlines six available, commercially viable technologies for reducing GHG at existing generating units, all of them taking the form of increased efficiency, i.e. heat rate improvement. These six technologies are as follows:

Combustion Control Optimization: identified technologies include neural networks. Expected Efficiency Gain: 0.15 to 0.84%
Cooling System Heat Loss Recovery: identified technologies include replacing the cooling tower fill (heat transfer surface) and tuning the cooling tower and condenser. Expected Efficiency Gain: 0.2 to 1%
Sootblower Optimization: identified technologies include intelligent or neural-network sootblowing (i.e., sootblowing in response to real-time conditions in the boiler) and detonation sootblowing. Expected Efficiency Gain: 0.1 to 0.65%
Flue Gas Heat Recovery: identified technologies include systems to recover energy lost in the flue gas to preheat boiler feedwater via use of a condensing heat exchanger. Expected Efficiency Gain: 0.3 to 1.5%
Low-rank Coal Drying: identified technologies include using waste heat from the flue gas and/or cooling water systems to dry low-rank coal prior to combustion. Expected Efficiency Gain: 0.1 to 1.7%
Steam Turbine Design: identified technologies include improved design of turbine blades and steam seals which can increase both efficiency and output. Expected Efficiency Gain: 0.84 to 2.6%

Looking at the range of efficiency improvements across these six technologies, it appears likely that the required GHG reductions (efficiency improvements) will be in the range of 0.5-1.5%. The reality is that the only way to reduce GHG emissions short of capture and sequestration is through improving efficiency; and there’s only a limited number of ways to do that short of massive boiler or steam cycle refurbishments.

The EPA mentions technologies such as optimization or turbine upgrades which are applicable to all steam-turbine generating units. Others are only relevant to boilers with systems in which these modifications apply. The range of efficiency improvements is the same range that NeuCo routinely achieves with our boiler optimization solution, BoilerOpt®, which combines the functions of both CombustionOpt® and SootOpt® solutions.

Final Thoughts
It remains to be seen when the EPA will publish the actual standards. Here we are more than a year later, with regulations already delayed once and supposedly being re-issued this May, it's still unclear as to how these regulations will take form. The Obama administration has been silent about the standard, which was sent to the Office of Management and Budget for vetting nearly six months ago. Clearly the issue is a political hot potato, particularly with the Presidential election in full-swing.

Looking at the entirety of the air emissions landscape as it affects our industry, the MACT rule appears to be firmly in place and the CSAPR rule is poised to be resolved in the near term with little modification. As for the GHG emissions for both new and existing power plants, the Congressional Review Act might be employed in efforts to block these regulations. However, most political observers believe these efforts cannot be successful under the current administration, as President Obama has repeatedly threatened to veto legislation that blocks EPA’s authority to promulgate these rules.

The issue of the EPA regulations, costs and benefits will likely continue to be a high profile issue. If history is any indication, these types of regulations will get worse before they get better, which is why most NeuCo customers I talk with are "preparing for the worst and hoping for the best."

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The Utility MACT: It's Now a Fact

Mon, 30 Jan 2012 13:51:00 -0600

As stated in my recent CSAPR post, the New Year has been a tumultuous period for power generators, with respect to both emissions regulations and other industry developments. In this post, I want to focus on the recently finalized US EPA Utility Maximum Achievable Control Technology (MACT) rule, as well as a few additional developments that have the effect of upping the ante for optimized boiler operations.

The Utility MACT was issued December 21, 2011. It was required by a court-ordered Consent Decree which arose from the litigation resulting from its predecessor, the Clean Air Mercury Rule (CAMR), which was vacated in 2008. The Utility MACT rule sets maximum achievable control technology (MACT) standards for coal and oil generating stations for removing mercury, acid gasses, and a variety of toxic metals from the flue gas for coal and oil-fired utility boilers. EPA projects that the Rule’s annual incremental compliances cost will be $9.6 billion.

More than two decades in the making, the Utility MACT rule has been a high-profile regulatory development, accompanied by the typical controversies over the costs, benefits and reliability impacts. In announcing the rule, EPA argued that it made a number of changes to provide more flexibility to utilities. As an indication of the interests at stake, the rule from the time it was first proposed to its final issuance drew more than 900,000 comments.

MACT Requirements
For coal-fired units, the Utility MACT limits emissions for hydrogen chloride (as a surrogate for acid gas hazardous air pollutants (“HAP”), filterable particulate matter (“PM”) (as a surrogate for non-mercury HAP metals), mercury, and organic HAP. The limits vary based on type of coal burned and whether the units are new or were already in operation when the final rule was published. Total non-mercury HAP metals and individual non-mercury HAP metals limits can be used as an alternate to the filterable PM limits. Coal-fired EGUs with flue gas desulfurization (FGD) units can use SO2 limits as an alternative to the hydrogen chloride limits.

The new rule creates a variety of new work practices standards. For example, units must burn natural gas or distillate oil during periods of start-up. Relevant emissions control systems must be operated during periods of start-up and shutdown. And, as discussed below, optimization of NOx and CO, combined with "best practices" efforts to maximize fuel efficiency must be demonstrated and documented for the EPA.

Compliance Schedules
All sources are given three years to comply with the Utility MACT. Sources can also apply to the EPA or appropriate state authority for a one-year compliance extension if the extension is needed to install controls—bringing the total compliance time to four years. The one-year extension is granted on a case-by-case basis.

To address concerns regarding reliability, the EPA has stated -- via administrative orders -- that it may grant some sources an additional year to comply. EPA will only grant these administrative orders to sources that are critical to electric reliability and, due to forces beyond their control, be forced to deactivate temporarily to comply with the Rule or are unable to install controls in time.

Final Rule Modifications
There were several changes made during the public review process embodied in the final rule, particularly allowing hydrogen chloride as a surrogate for acid HAPs and filterable particulate matter as a surrogate for non-mercury HAP metals. The net effect is that substantially fewer coal-fired units will need to install costly scrubbers.

There was also language added to the final rule explicitly referencing "neural network optimization” systems as qualifying for "optimizing NOx and CO." Similarly, the final bill has language rewarding boilers benefitting from "neural network optimization" by delaying the initial EPA "best practices” evaluation by a year and reducing the required frequency for subsequent evaluations from every 36 months to every 48 months. The motivation for mandating these best practice operating protocols is to ensure that HAPs included in the rule are not measurable through current CEM technology (such as dioxin and fiurin) and are being minimized through the best achievable operating efficiencies. More on this below.

Boiler audits to ensure "best practices" efficiency
All publicly released drafts of the rule state that the non-measurable HAPs, such as those described above, would be regulated through requirements in which owners and operators of affected boilers demonstrate they are employing all available efforts to minimize these pollutants through maximizing the efficiency with which the fuel containing them is converted into electricity. As a testament to how much the industry objected this provision, the required frequency has gone from 12 to 18 to 32 months and now 48 months with an optimizer in three successive versions based on the public comment process.

This explicit recognition of the MACT compliance value of optimization not only reduces a painful regulatory burden by 25%; but it also signals that the EPA views closed-loop optimization as part and parcel of the best practices boiler operations as they pertain to minimizing non-measurable HAPS (i.e. fiurin and dioxin). Here are some excerpts from the final rule that were not included in earlier versions:

The initial compliance demonstration for the work practice standard of conducting a tune-up may occur prior to the compliance date of the rule, but must occur no later than 42 months (36 months plus 180 days) from the compliance date of the rule or, in the case of units employing neural network combustion controls, 54 months (48 months plus 180 days).

Subsequent demonstrations of these standards must be conducted at each planned major outage and in no event less frequently than every 36 calendar months, with an exception that if the unit employs a neural-network system for combustion optimization during hours of normal unit operation, the required frequency is a minimum of once every 4 years (48 calendar months).

Each work practice shall also entail optimizing combustion to minimize generation of CO and NOx. NOx optimization includes burners, over-fire air controls, concentric firing system improvements, neural network or combustion efficiency software, control systems calibrations, adjusting combustion zone temperature profiles, and add-on controls such as SCR and SNCR; CO optimization includes burners, over-fire air controls, concentric firing system improvements, neural network or combustion efficiency software, control systems calibrations, and adjusting combustion zone temperature profiles.

One of Several New Efficiency Drivers
The Utility MACT rule is just one of the many developments making fuel efficiency (i.e. heat rate) a bigger concern which has historically been the case. In addition to the above-described need to demonstrate efficient boiler operations out of concern for non-measurable HAPS; the formulae for HG and other measurable HAPS are focused on a year-by-year variability. Since the new MACT limits are not substantially lower than current emissions rates at many units, anything that increases fuel efficiency, reduces year-to-year variability, allows better planning for physical sorbent injection modifications and reduces the sorbent needed to make the various limits will be economically beneficial for MACT compliance.

Another part of the incentive created to maximizing fuel efficiency stems from the "hair trigger" phenomenon for activated carbon, where meeting HG limits with even a few percentage points lower sorbent injection rates can mean the difference between being able to sell fly ash or having to truck it away to a landfill. For many units, the ability to implement sorbent injection while still remaining under the maximum carbon content threshold required to continue selling fly ash will mean millions of dollars of otherwise lost revenue and increased disposal costs.

Another factor stems from recent unprecedentedly low natural gas prices. As I’ve previously blogged about at some length, my view is that these recent prices have resulted from the combination of things. First, the lingering effects of the "Great Recession." The ability to store natural gas in large quantities underground makes for something on the order of a year-long delay in the effects of fundamental supply and demand on price behavior. Second, I believe that natural gas markets have not yet internalized the anticipated double-whammy effects of environmental concerns (groundwater contamination, methane emissions, etc.) and limitations in the availability of the large amounts of water required by this process in the first place on the extent to which "fracking" can make sustained long-term contributions to increasing domestic natural gas supply.

The biggest effect of these low natural gas prices on coal-fired generating units is that the latter are now competing with gas-fired combined cycle plants (CCCTs) not only in organized locational price markets, but also in traditionally regulated markets where there is a centralized dispatch using "merit-order" algorithms to determine which units are run to meet demand at any particular time of the day, season or week. Back when natural gas prices on heat content (i.e. $/mmBtu) were a multiple of coal prices, even the most inefficient smaller coal units would be "in the money."

Currently however, even large, relatively new and efficient coal units are finding themselves shut down or at minimum load being displaced by combined cycles with slightly lower operating costs at today's low gas prices. The difference of even 50-100 BTU/KWh can now make the difference between generating profitable revenue or losing money sitting idle.

Tying these somewhat disparate threads together and attempting to sum things up, a confluence of regulatory developments and market conditions have combined to make squeezing every last BTU from your fuel more important than ever. And with the provisions for optimization written directly into the final Utility MACT rule, the 1200 coal-fired units affected by the rule, generators can simultaneously increase efficiency , be in a better positions to comply with the Clean Air Act and its Amendments, and minimize the frequency with which the EPA is inspecting your operational practices. Makes sense to me. Does it to you?

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Recent Developments Affecting US Coal-Fired Power Generation: When is Rains it Pours

Thu, 19 Jan 2012 10:12:00 -0600

Between two substantial events affecting rules regarding emissions regulations by the US EPA, unprecedented low natural gas prices, and what appears to finally be a sustained economic turn-around and associated impacts on electricity demand, it has truly been an eventful New Year for the power generation industry. Let me focus on CSAPR now, and will opine on the other topics in the days to come.

Arguably the most newsworthy and certainly the most surprising, the United States Court of Appeals for the D.C. Circuit issued a ruling on December 30, 2011 to stay the controversial Cross-State Air Pollution Rule (CSAPR), which was scheduled to take effect on January 1, 2012. It required 28 Eastern and Midwestern states to reduce SO2 and NOx emissions, accompanied by a supplemental rule finalized in December mandating five states to make summertime NOx reductions as part of CSAPR ozone season control program; which wasdesigned to assist states in attaining ozone and fine particle National Ambient Air Quality Standards.
The D.C. Circuit Court will be holding hearings in April 2012 to rule on the case. In the meantime the EPA is now busy reinstating allowance trading for the Clean Air Interstate Rule (CAIR), which it vacated in 2008 but re-instated as an interim regulation until a suitable replacement rule was promulgated.

The postponement of CSAPR obligations is a victory for parties objecting to it, but the EPA will be able to finalize “technical adjustments” before the rule is put into effect. While EPA has expressed hopes in a mid-2012 "go-ahead" ruling, in my view, actual implementation during the fall presidential race is "not bloody likely."

The Court's 11th hour decision took industry experts and energy markets alike by surprise. Many observers had anticipated an exemption for Texas due to both the large change in compliance requirements relative to CAIR and reliability issues related to low capacity reserve margins associated with coal units being taken offline and/or retired. The surprise mainly stemmed from the fact that this same court when vacating CAIR in its order stated that it would “not tolerate any unnecessary delays”

While the timing and substance of the court's ultimate ruling on CSAPR remains uncertain, all observers acknowledge that the EPA is legally required to address interstate emissions transport. Most of the folks running plants and responsible for corporate emissions compliance have told me their companies expect that CSAPR or something very like it will be in place next year at the latest, and are continuing along the same path before being surprised by the stay.

I agree with them that the rule will likely be re-instated in a form close to or identical to that which has been stayed, and that the courts ruling will embody some level of urgency with respect to the timing. Of course another uglier possibility would be given the difficulties in designing a rule that can legally deal with interstate emissions transport; the court avoids any emissions-trading program whatsoever. In this scenario, the only possible outcome would be a command-and-control regime more akin to the manner in which the CAA/CAAA Best Available Retrofit Technology (BART) requirements are being applied in states not covered by CSAPR or New Source Review (NSR) litigation which has and continues to be applied on a case-by-case basis in the Midwest and Southeast. But let’s save that topic for another blog…

In any case, this stay will buy power generators more time in the near term; however the future has never been so unclear for many. You will be hearing from me on the recently finalized Utility MACT rule shortly.

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Rumors of Coal's Death Greatly Exaggerated

Mon, 21 Nov 2011 14:38:00 -0600

Earlier this week, a column from the Public Utilities Fortnightly Spark website got me thinking about an issue I haven't focused on in a while -- the role of natural gas prices in shaping the economics of coal-fired power generation. I’ll chalk it up to my lack of focus being preoccupied with trying to figure out CSAPR; our ever-morphing friendly ghost. But the upward pressures on natural gas prices -- which largely determines the financial performance of coal-fired generation in wholesale power markets -- combined with a variety of other emerging developments, suggests that coal will continue to play a vital role in our country's energy future.
The observation on natural gas prices that caught my eyes was:

“Even with recent large natural gas discoveries, significant technology advances, and higher-than-average inventories, the supply of natural gas is not elastic enough to handle the price impact of significant demand increases. As a result, as natural gas prices rise, the economics of environmental compliance investments for coal plants will also change. The result will be to push coal back into the money despite very high costs for compliance with potential EPA carbon emissions limitations and requirements. In any event, the prospects for increased natural gas consumption in the utility sector are enough to indicate that gas prices likely will rise in the short term. The real questions everyone should be asking are how high and how fast?”

There are several additional factors working against the demise of coal-fired generation. For one thing, constraints in both electricity transmission and natural gas transportation infrastructure are limiting how much coal-fired capacity can be retired and replaced with gas. In the last two years, several requests to retired older medium-sized coal units have been rejected by their respective ISO's on the basis or reliability and grid stability concerns. Moreover, much of the transmission capacity available for wind farms that are already being developed are now being employed to move the tremendous amount of new wind generation from the rural areas where this resource is viable to the urban locations comprising the greatest source of electricity demand.

Since I’m on the topic of wind, I can't help but to digress and note the tremendous number of new wind turbines that have sprouted up along the rural landscape since I last traversed the state of Iowa via Interstate 80. Literally hundreds of them, for as far as the eye can see. While farming is still the mainstay in this part of our country called the "Breadbasket of America" it appears that much of what is being farmed is wind power; and a large proportion of the "bread" now takes the form of royalties that traditional farmers are deriving from the electricity being generated on their land.

Of course the additional demands placed on our bulk power transmission system by wind power pale in comparison with the vastly increased wholesale power trading that has characterized US bulk power markets since the passage of the Energy Policy Act of 1992. Our incredibly capital-intensive historical electricity infrastructure was developed largely on the premise of vertically integrated regulated utilities serving their own retail customers with interconnections existing primarily to deal with power reliability contingencies. This same system is now being used to support extensive and far-flung wholesale power trading both within and between the major wholesale markets. And expanding on this system would be both enormously costly and institutionally difficult. All of these factors serve to increase our dependence on coal-fired generation. This being said, both existing and potential new plants still no doubt face difficult challenges. These include:

•   no end in sight of more stringent limits on NOx and SO2,
•   the traditional "criterion pollutants" (e.g. the CSAPR program slated to start in less than two months);
•   renewed emphasis on regulation of mercury and other hazardous pollutants;
•   and continued uncertainty about when and how CO2 emissions will be regulated in the US.

In my view, however, coal-fired generation's will likely continue playing a strong role in our near- and medium-term future (I define "medium-term" as the next 15-20 years). In addition to likely natural gas price increases and reliability constraints, two additional reasons why coal-fired generation will remain vital to the US energy picture include:

1. Even the most optimistic projections for renewables will make for marginal contributions, and while they create new challenges for base-load generation they cannot replace it; and
2. The electrification of the US transportation sector with its large demands for battery charging predominantly at night will not only increase overall demand, but also bring former base-load coal plants that are now cycling back to base-load, and make coal-fired plants that are still base-loaded even more financially attractive.

These developments, combined with the ongoing progress of clean coal technologies such as multi-pollutant removal systems, biological processes for controlling CO2, commercialization of large scale carbon capture and sequestration (CCS) technologies, and new ultra-supercritical boilers create the potential for a vibrant future where we maintain energy security through using our most abundant domestic energy resource while meeting both existing and emerging environmental challenges.

I predict that coal will be a necessary part of the U.S. generation mix in the foreseeable future; but that we must diligently work together to ensure that this generation resource be employed in the cleanest and most efficient manner possible.

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CSAPR Update: The Kinder, Friendlier Ghost

Fri, 14 Oct 2011 07:47:00 -0600

The close of the time period for petitioning the US EPA's Cross-State Air Pollution Reduction (CSAPR) rule was accompanied by an EPA announcement with proposed changes to the rule, and 8 states filing petitions contesting it (in addition to Texas which had already filed a petition). These changes have the effect of making the rule less onerous than the original, which was issued last July to take effect on January 1, 2012. The start time for the state budgets and maximum assurance levels and allowance trading remains in place for January 2012, despite a 30-day comment period on the proposed changes.

Some small adjustments were made affecting a number of state-level CSAPR budgets and unit allocations, in effect relaxing the required reductions between 1-4%. The basis of these changes included erroneous assumptions in the original modeling regarding SCRs in-place and also states where it became clear that the original budgets would have caused "non-economic operations of several units, (aka de-rates) for large units with relatively low variable costs.

The biggest change, however, is delaying the onerous "two-for-one" allowance forfeiture and financial penalties when maximum assurance limits are exceeded until Phase 2 of the rule, which takes effect January 2014. This change is described in the Fact Sheet accompany the proposed changes as follows:

"EPA is amending the assurance penalty provisions of the Transport Rule to make them effective January 1, 2014. This change takes account of the fact that the revisions described above are being proposed, and any information described above concerning requested additional revisions may be submitted, close to the commencement of the Transport Rule programs. The proposed amendment to the assurance provisions is intended to promote the development of allowance market liquidity as these revisions are finalized, thereby smoothing the transition from the Clean Air Interstate Rule (CAIR) programs to the Transport Rule programs in 2012."

I believe that both the relaxed budgets and assurance limits (based on a percentage beyond the budgets designed to account for "natural" year-to-year variability in emissions output for any given generating unit) and deferral of the forfeiture and financial penalty provisions will make boiler optimization all the more attractive as a primary compliance method for CSAPR. The smaller required percentage reductions will further increase the likelihood that the 10-15% average NOx reductions typically provided through boiler optimization will be sufficient to achieve compliance.
The two-year deferral of penalties and trading restrictions will make for a more robust and liquid trading market during the first phase of CSAPR. The increased liquidity and less restrictive trading provisions will provide every generating unit included in CSAPR a direct financial incentive to minimize the allowances needed to purchase or maximize the surplus allowances available to sell or bank for future compliance needs.

On the topic of banking, my sense is that there is a strong incentive to maximize the allowances available to a bank for post-2014 usage due to a combination of the ratcheting down of the state budget levels, uncertainty on how economic conditions will affect generation demand and dispatch patterns, the draconian nature of the “two-for-one” forfeiture and $37k per ton-day financial penalties that will take effect in January 2014. Simple logic suggests that no generator would want to forgo any action that cost-effectively minimizes allowances used during these first two years of CSAPR, particularly if that action, such as the adoption of boiler optimization technology, pays for itself in fuel savings and improved commercial availability (such as reduced boiler tube leaks from less soot blowing or fewer de-rates from slagging or fouling).

Then, there’s the issue of how and when the petitions that have been filed might affect the implementation of CSAPR. I am not a lawyer, but my understanding is that the rule will be implemented as proposed until if and when such time the US Circuit Court modifies or overturns it, unless the court grants a stay, as requested by several of the petitioners. While it is possible such a stay could be granted, I believe (as do most of the petitioners) that this would be unlikely given the experience with CAIR, the delay between the overturning of CAIR and the January 2012 CSAPR deadline, , and the court's recognition of the urgency with which the legal requirements associated with the Clean Air Act of 1970 (CAA) and CAA Amendments of 1990 must be addressed.

My read on the CAA and CAAA is that one could not imagine any rule "kinder or gentler" to the affected generators than CSAPR which would be considered consistent with the legal obligations of these landmark pieces of legislation. Remember, CAIR was tossed out because it was “not stringent enough” to ensure against upwind states interfering with the ability of down-wind states to comply with NAAQS. As one attorney specializing in air emissions law remarked, CSAPR "reads like a 100-page legal response to the Circuit Court's ruling on CAIR."

This logic here is all the more compelling given the significant concessions the EPA has made in response to generator concerns about how CSAPR would affect their operations and associated costs to electricity consumers. In fact, it will beinteresting to see if some states withdraw their petitions in response to these concessions, since they were announced on the same day that the 8 out of 9 petitions were filed.

What I can imagine is that the court -- in ruling on the petitions -- sets a deadline for finalizing the new NAAQS ground-level ozone limits. What CSAPR needs to do for NOx reduction in Phase 2 and beyond to provide compliance with CAA and its amendments depends entirely on whether that NAAQS limit is set at 70 or 65 ppm. And the regulatory uncertainty associated with the difference between a $13 billion and $90 billion compliance tab is crippling to the industry and the economy as-a-whole.

That being said, what is legal or rational, or good for the power industry and the economy as-a-whole may or may not have anything to do with one another. I do, however, believe it very unlikely that anything less stringent than CSAPR as most recently modified will pass muster with the Circuit Court given their ruling on CAIR, and also unlikely that the same court would further delay CAIR's replacement given the urgency in its own ruling that CAIR's shortcomings be addressed.

*UPCOMING WEBCAST: We are hosting a live webcast on Nov. 3rd, 2011 at 11:30am/EST to discuss CSAPR's implication on the power industry, what it means for your plant and how it's different from past emissions regulations. We'll also highlight how BoilerOpt® can improve overall unit performance, reduce NOx, and increase boiler reliability which results in fewer adverse consequences associated with low-NOx operations, including less slagging, water wall corrosion, ammonia slip and air heater fouling. To register visit: http://www.brighttalk.com/channel/5672

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Delay in New Ozone Standards for NAAQS: What it Means Now and for the Future

Mon, 12 Sep 2011 11:59:00 -0600

On Friday of last week, President Obama overruled the stringent new ozone standards proposed by the U.S. Environmental Protection Agency, citing concern about their potentially adverse impact on jobs and overall economic recovery. Just as his predecessor George W. Bush did six years earlier, President Obama rejected the findings of his own Administration's EPA, despite their unanimous recommendation by the agency's independent panel of scientific advisers. In so doing, Obama directed current EPA administrator Lisa Jackson to withdraw the agency's plans for reductions in concentrations of ground-level ozone, the primary component of smog. The stated rationale for this executive decision was to reduce regulatory burdens and uncertainty for businesses at a time of widespread concern about an unsteady economy.

The Obama Administration's initial plan had been to revise the weaker 75 PPM ozone level limits which had been put in place by President George W. Bush over the objections of his Administration's EPA panel of science advisors, who had called for more stringent regulations based on their interpretations of applicable US environmental law. As recently as July, Obama's EPA advocated overturning that weaker standard, warning that it likely would not survive a legal challenge, because of its failure to satisfy the agency's panel of scientific advisors under either administration.

The history of the issue has its roots in the Clean Air Act of 1970 (CAA) and the Clean Air Act Amendments of 1990 (CAAA) as it concerns the health impacts of ground level ozone and the smog it creates. The decision immediately at hand on the appropriate ozone limit stems back to January 2010, when the current EPA under Administrator Jackson proposed to decrease the concentration of ground-level ozone from Bush Administration levels to somewhere between 60-70 parts per billion. In March of this year, agency advisors, citing "sufficiently certain" scientific evidence, again unanimously declared their conviction that this new standard was essential to protect public health. In the wake of its decision overruling the EPA last week, the White House defended its decisions, stating that the science behind the new ozone limit itself needs to be updated, and that a new limit will be issued in 2013 based on the most current scientific evidence.

While Friday's decision represents dodging or at least delaying a costly and far-reaching new set of emissions reduction requirements, it will not fundamentally affect most elements of the Cross-State Air Pollution Reduction (CSAPR) rule, which was finalized this summer and goes into effect four months from now in January, 2012. CSAPR's the state-specific caps, unit-specific allowance allocations, associated NOx and SO2 reductions, allowance forfeiture provisions and penalties for non-compliance will all remain in place. These elements were described last month in my blog of August 11. The NAQQS decision however, does affect key components of the CAA of 1970 and the 1990 CAAA, and in so doing also does has some implications for CSAPR. Specifically:

Counties across the country that were expecting CSAPR to re-designate their attainment status will now be in limbo until the new ground level ozone limit is set in 2013;
Questions about additional new or expanded facilities triggering NSR will accordingly be on hold with the future requirements unknown;
Strategic repowering and/or retooling to comply with the CSAPR may not trigger NSR requirements that would have been triggered under the revised ozone standards; and
More stringent and costly emissions reduction and offset provisions under CSAPR initially planned for 2014will be on hold until the Administration signals its intent on the rule.

In response expected concern and/or litigation from environmental interests and NGOs, the Obama administration is already positioning CSAPR -- since it is a final rule and will accomplish substantial emissions decreases with or without new Ozone standards -- as accomplishing much of the air quality and health improvements for which the tightened NAQQS ozone standards were intended.

As a final observation, I should point out that the NAAQS decision announced Friday is not having any observable affect on allowance price behavior for the affected CSAPR markets. As a recovering economist, I firmly believe that market behavior trumps analysis. As of this morning, NOx and SO2 markets for CASPR SO2 are trading around $2,500 per ton; and NOx Seasonal and annual are around the $3,750 level. This market behavior consistent with what our customers have been telling me in recent weeks -- that they expect average NOx allowance prices to be at least three times higher than EPA's initial projections when CSAPR was finalized just two months ago. So while Friday's decision on NAAQs may ameliorate or at least stave off the huge capital investments required by a reduction from 75 PPM to 70 or 65 PPM, it does not remove the incentive for finding the quickest, most cost-effective means for achieving the near-term emissions reductions still required as of January 1 for CSAPR.

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Why the new CSAPR Rule Creates an Urgent Need for Action

Mon, 15 Aug 2011 11:28:00 -0600

I described the overall Cross-State Air Pollution Rule (CSAPR) in my previous post and thought it might be worth delving a bit deeper into the mechanics and implications of the rule as it affects NOx. We are taking proactive steps to work with generators affected by CSAPR, but not included in CAIR (Nebraska, Kansas, and Oklahoma) and those states where the incremental reductions required by CSAPR are most substantial (such as Missouri and Texas), in addition to many of our existing customers that are expanding on or accelerating their adoption decisions for our optimization technology to address the near-term compliance challenges created by the new rule.

In this post, I do not distinguish between CSAPR itself and the supplemental rulemaking issue at the same time and intended to be implemented in parallel to it. Based on the additional analysis of air quality information performed in finalizing CSAPR, the EPA is requiring sources in Iowa, Kansas, Michigan, Missouri, Oklahoma and Wisconsin to reduce NOX emissions during the summertime ozone season, which has increased the total number of states covered by the rule from 27 to 28 and adds summer ozone season limits to the annual limits under CSAPR for five of these six states. The aggregate incremental NOx reductions required by the first phase of the rule (January 1, 2012) are relatively modest in large part, due to the substantial emissions reductions associated with investments made in anticipation of the earlier EPA CAIR rule; which was struck down by the DC Circuit Court in August 2008. The short implementation time-frame , combined with the fact that most units in the affected 28 states already have low-NOx burners and over-fire air have created urgent needs for action for many generators in these states.

To understand the urgency, it might help to understand the mechanisms by which allowances are allocated and the state-specific NOx limits which will be enforced. Every affected unit will be allocated a number of allowances equal to its historical emissions minus the reduction required to meet the new state limit, (which is allocated to each unit based on its heat input relative to the total heat input for all affected units.)
The average reduction for Phase 1 is 15% for both the 5-month Ozone Season and the Annual Market, but varies across states based on the EPA's models of each state's impact on the ability of down-wind states to comply with the ground-level ozone and PM 2.5 requirements of the Clean Air Act and its amendments.

In order to comply with CSAPR, units must hold an allowance for each ton of either SO2 or NOX emitted. If units have excess allowances, they may bank the units for compliance in future years. However, if units have a shortage of allowances, they are subject to an automatic penalty as a result of their inability to comply with the rule. Companies must provide one allowance as an offset and two allowances as a penalty for each ton of emissions in excess of the amount of allowances held. The surrendered allowances must be submitted for the control period in the year immediately following the year when the excess emissions occurred.

So if each unit is under its limit it surrenders one allowance for every ton emitted. If the generator cannot make its allocated contribution to the newly required state NOx limit, it then must surrender not only one allowance for every ton over the limit, but two more as a penalty. And if that generator cannot buy enough allowances to cover the offset plus the penalty allowances, a fine will beimposed by the EPA of $37,000 per ton/per day.

So, for example, a 600 MW unit which is 10% over its limit for one month and can't cover it with allowances, would be fined more than two million dollars just for that one month!

Within the last few weeks, several generators I've talked to are 1) frantically looking for ways to comply with the rule and 2) believe that the only near-term way to comply with the 2012 CSAPR requirements will be de-rating their units (and many of these units are low-cost base load units, which will have the effect of increasing wholesale power prices.) While units lucky enough to avoid de-rates may benefits from this, those who do require de-rates will be foregoing even more revenue. In this scenario, every pound of NOx reduction equates to increases MWh available for selling, and as noted, quite possibly selling at higher than historical prices.

However, it is not merely units facing de-rates where CSAPR has upped the ante for the NOX reductions associated with NOx reduction. Hopefully most of you remember back in the 2003-2004SIP Call era when $1500/per ton NOx allowance prices created a strong business case for combustion optimization and in fact, put NeuCo on the optimization map.

But those $1500/ton allowance prices applied to the 5-month Ozone Season only, which on an annualized basis was $625 per ton. Current EPA estimates for 2012 of $1300/ton for the Ozone Season and $600 per ton for the Annual NOx Market create an annualized value of $1042 per ton, a 62% increase! And the per-ton value really only applies for those generators that are fortunate enough to be able to over-comply. The value of allowances surrendered for non-compliance will be three times as high, assuming that sufficient allowances are available for purchase. If they aren’t, then even the more draconian $37,000 per ton per day penalty comes into play.

The short compliance time-frame for CSAPR, coupled with the lack of available alternatives for reducing NOx with traditional hardware retrofits and the harsh consequences of non-compliance is having an unprecedented effect on NeuCo's business. Customers who currently have BoilerOpt™ installed on some units are accelerating what were 2012 plans for additional units are moving forward in 2011 with additional units.

Similarly, existing CombustionOpt®customers who had planned to add SootOpt® next year or who have been trying to get boiler cleanliness- related performance improvements through traditional "intelligent sootblowing" (ISB) systems are moving forward with adding SootOpt ahead of schedule. They recognize the immediate benefit with regards to integrated optimization of combustion and heat transfer processes which will result inNOx reductions and fewer adverse consequences associated with low-NOx operations. And as I mentioned earlier, their is a large amount of market activity around new optimization initiatives in the states not included in CAIR but affected by CSAPR.

While all of this new business is keeping us very busy, I do have concerns about the medium- and long-term implications for the US power generation industry. If you look at the aggregate NOx reductions needed for the January 2012 deadline, combined with the second round of increases that goes into effect in 2014, even the application of BoilerOpt to every single operating unit is not going to be sufficient and substantial. Additional combustion and post-combustion modifications are most likely going to be required.

The supply chain for such modifications is already beginning to be stretched and will be stretched further even for the 2012 requirements, let alone those in 2014. And the outages required for such modifications at minimum are going to result in higher wholesale power prices, and possibly even grid reliability concerns which already have been emerging for the first time in several years with this summer's sustained heat and humidity throughout much of the country.

But our fossil generation industry has consistently proven to be resilient in the face of adversity, and I am confident it will find a way through the next wave of challenges. And the one thing NeuCo has proven overwhelmingly throughout its history: that integrated optimization not only helps boilers operate more cleanly and efficiently, it also minimizes the adverse consequences of the hardware modifications needed to meet ever more stringent emissions regulations.

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EPA Issues Final CAIR Replacement Rule Effective January 1, 2012

Tue, 19 Jul 2011 10:29:00 -0600

On July 6, the Environmental Protection Agency (EPA) finalized the Cross-State Air Pollution Rule (CSAPR), which requires 27 states in the eastern and mid-western U.S. to substantially improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in so-called "down-wind" states. It replaces and strengthens the EPA's 2005 Clean Air Interstate Rule (CAIR), which the U.S. Court of Appeals for the D.C. Circuit ordered the EPA to revise in 2008.

While the new ruling allows CAIR to remain in place temporarily until the agency works to finalize this rule, the uncertainty around what would replace it puts emissions reductions on hold and effectively decimates the CAIR allowance markets for both NOx and SO2. Although the EPA announced an intended CAIR replacement, referring to the "Transport Rule" a year ago, that proposed rule described three very different regulatory mechanisms by which the state-specific reductions believed necessary to allow all affected states to comply with the Clean Air Act of 1970 and its amendments of 1990.

That fact that the EPA has implemented CSAPR is no surprise -- they were ordered to find a replacement for CAIR by the D.C. US Circuit Court when that court struck down CAIR in July of 2008. Moreover, the Clean Air Act’s “good neighbor” provision (section 110(a)(2)(D)(i)(I)) requires upwind states to control emissions that affect the ability of downwind states to meet federal air quality regulations. In 1997, and again in 2006, the EPA tightened air quality standards for ozone and particulate matter. The EPA's model indicates that emissions from 27 upwind states contribute to violations of these standards in downwind states. If the EPA did not regulate this interstate transport of ozone and particulate matter, downwind states would likely sue to force the EPA’s hand, as they did last decade which resulted in additional NOx regulations referred to as Section 326.

In a supplemental rulemaking based on additional analysis of air quality information, the EPA’s also proposing to require sources in Iowa, Kansas, Michigan, Missouri, Oklahoma and Wisconsin to reduce NOX emissions during the summertime ozone season. This proposal would increase the total number of states covered by the rule from 27 to 28; and add summer ozone season limits to the annual limits under CSAPR for five of these six states.

So how does CSAPR compare to CAIR and the Transport Rule that was initially proposed to replace CAIR? For one, it is more aggressive than CAIR for both NOx and SO2, with respect to both the level of reduction and geographic scope (taking into consideration the supplemental ruling described above). Secondly, there are state-specific caps intended to avoid emissions from upwind states interfering with the ability of downwind states to comply with the SO2, NOx, ground-level ozone, and PM 2.5 requirements associated with the Clean Air Act, its Amendments and the National Ambient Air Quality Standards (NAAQS) promulgated in response to them.
And thirdly, it most closely resembles the most "market-oriented" of the three alternatives described in the proposed Transport Rule, which allowed for intra-state allowance trading and "limited" interstate trading whereas the onus was on the traders to demonstrate that associated interstate transactions were required to maintain the reliability of the bulk power electric system. CSAPR not only allows for intra-state trading but also as much state trading that can be done while remaining within the state-specific caps imposed by the new rule, with no other constraints.

But what is still unclear is the extent to which the state caps will limit interstate allowance trading or the liquidity and functioning of the relevant interstate markets. In the next coming weeks, I will be doing more research and talking to the environmental folks within NeuCo's customer base as this new rule becomes clearer. I’ll also post a supplemental blog as a follow up to this as we roll up our sleeves, examine the details and crunch the numbers.

It is fair to say that CSAPR is less in command and control in nature than any of the three alternatives proposed in the Transport Rule, especially the two that essentially ruled out meaningful allowance trading. For that, those of us concerned with the cost-effectiveness of emissions compliance can be thankful. The DC Circuit Courts ruling that struck down CAIR made it clear that any replacement rule would need state-specific caps. So from that perspective, my view is that we’ve got a rule which is as good as anything I can imagine to help pass legal muster and be consistent with the Clean Air Act and its amendments.

Yet, what is very clear is the rapidly approaching January 1, 2012 deadline requiring the incremental NOx reductions required by CSAPR to be made in an entirely unprecedented short time-frame. This is especially the case in areas covered by the new rule but not by CAIR, such as Kansas, Western Missouri and Iowa. Many generators in these areas will attest, the less than six months between now and January barely leaves any time for the procurement and installation of low-NOx burners (LNBs), let alone more complex retrofits such as over-fire air/LNB combinations or SNCRs.

My final observation relating more than seven years experience with NOx emissions compliance since the CAAA SIP call and associated Section 326 requirements became effective in early 2004, our industry has moved from viewing optimization as an alternative to boiler modifications to embracing it as a valuable complement to such modifications. In recognizing that, all such modifications introduce design compromises, complexity and trade-offs ideally suited for comprehensive integrated optimization of combustion processes and boiler cleanliness. These attributes, combined with the short implementation timeframe required by CSAPR and the efficiency drivers for the additional recent EPA rules on CO2 and embodies in the Utility MACT suggest that we’ll be facing very busy days ahead.

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Reflections on the CCPI Project at NRG Limestone; Q & A with NeuCo Product Manager Rob James

Mon, 21 Mar 2011 11:41:00 -0600

NeuCo has been working with the U.S. Department of Energy (“DOE”) under the Clean Coal Power Initiative (CCPI) program for almost a decade. Our first project, which took place at Dynegy’s Baldwin Energy Complex in Baldwin, IL, was completed in 2007. In 2006, NeuCo also began working on a Round 2 Mercury Specie and Multi-Pollutant Control Project at NRG’s Limestone Generating Station in Jewett, Texas.

After years of intensive efforts from NeuCo, Limestone, DOE and vendor partners, the Round 2 project recently concluded with the publishing of the final technical report. The project’s intent was to demonstrate the ability to affect and optimize mercury speciation and multi-pollutant control using non-intrusive advanced sensor and optimization technologies. Final analysis concluded that the plant significantly reduced NOx emissions, improved heat rate, successfully changed its fuel blend to reduce Mercury emissions, and instituted a streamlined equipment anomaly detection and diagnostics system.

Rob James, Product Manager, was the NeuCo project lead on both CCPI projects. We got a chance to sit down with him and ask a few questions.

How does the CCPI Round 2 project at Limestone compare to the CCPI Round 1 project at Baldwin?
The challenges presented by Round 1 at Baldwin and Round 2 at Limestone were completely different. At Baldwin we were essentially developing version 2 of the ProcessLink® platform and building three new product applications on it at the same time; Limestone was about unit-wide optimization and incorporated a lot of third-party instrumentation. Limestone was a huge integration challenge that required more people and systems to work together.

Any lessons learned from Round 1 to Round 2?
From Round 1 to Round 2, ProcessLink continued to improve and evolve such that by Round 2 we were able to attack a much more diverse set of problems, use more advanced approaches and be more efficient about it.

What are some of the things about the Limestone project you are most proud of?
Given the ambitiousness of this project and the huge number of moving parts, I’m proud of how we were able to adapt to the changing set of constraints in a way that provided a lot of utility and met a key set of investigative goals. For instance, we had to respond to changing economic drivers, such as the changing cost-benefit relationship between NOx and heat rate and changes in the value of NOx and SO2 credits, as well as a range of equipment and instrumentation constraints. Reliably measuring Mercury in multiple locations, over a long period of time, was also a major challenge.

We felt it was really important to balance the needs and wishes of all project investors. While we were asking a number of important investigative questions and searching through a large array of uncertainties, we really wanted to be useful to the plant in the short-term and in a concrete way. I believe we were able to do that. That is what our stuff is good at – attacking the combined challenge of discovery and value delivery.

One of the specific outputs of the project I’m most proud of is ProcessLink’s enhanced Optimization Measurement Tool, which structures an interactive on-line benchmarking process. I believe this is one of the main requirements for operationalized AI. Because benchmarking is so challenging in complex, noisy situations (as are often found in this industry), it’s often either dismissed as infeasible or approached naively. With optimization we do not have that luxury; we really need to be able to define and quantify (i.e. measure) simultaneous change in multiple related dimensions in order to apply some real notion of “good” and “bad” to how things are going. Without a tool to help do this, there’s no way I could have developed a data-driven report that addressed the significant questions the project sought to answer.

What were some of the biggest challenges?
Integrating all of the different types of instrumentation was harder than we thought. For instance it was really difficult to get reliable Mercury measurements for use by the optimizer in the places we wanted them – i.e. at the ESP inlet, FGD inlet and FGD outlet. These are just tough places to put sensitive instruments and analyzer packages.

You worked closely on this project with Steve Piche, NeuCo’s Director of Research & Development. Could you discuss his contribution?
Steve was involved in all aspects of the project. He is a real live math freak and one of my favorite teachers on this and many other projects. Steve is especially knowledgeable about modeling and process chemistry, and was solely responsible for the development of the Hg VOAs (Virtual On-line Analyzers), without which we could not have done the project. It means a lot to me to work with guys like Steve.

Of course, many others at NeuCo contributed a tremendous amount to the project as well – not to mention all the people from the plant that we were able to learn a lot from.

Any fond memories of your trips to Jewett, TX that you’d care to share with us?
One blazing hot afternoon I was driving to the plant and a big thunderstorm popped up. I pulled off the main road to watch it hit. I had the world to myself for awhile and was expecting a tornado to appear any minute. The Texas countryside is really beautiful when the storms roll in.

Jewett also has at least one great hole-in-the wall Mexican restaurant that makes excellent fajitas. A number of guys from the Austin office can vouch for those fajitas.

Another cool thing about Jewett – and I only recently found this out – it’s the birthplace of Marine Corps Sergeant Romus (RV) Burgin, whose experiences on Peleliu and Okinawa during WWII were dramatized in the HBO Miniseries The Pacific, which I really appreciated.

How many rounds of edits did you and the DOE trade before agreeing on the final report?
I think it was five. That’s less than the nine rounds for the first CCPI project – probably because the Limestone report was more than 300 pages long…

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Observations on the State of the Industry

Mon, 28 Feb 2011 10:09:00 -0600

My colleague Ray Johnson summarizes his experience at the recent EPRI & Reinhold Conference: I have attended both the EPRI Heat Rate Conference and the Reinhold NOx Conference for the past several years. I have delivered presentations at both those conferences concerning the improvements NeuCo has made for customers applying optimization technology, talked with many customers and suppliers, and attended presentations focused on a variety of projects from both suppliers and utility personnel. The contrast this year with previous years was telling. While there were some definite and interesting advances in both topic areas, the overwhelming theme was our industry's state of confusion. People are concerned, management is frustrated, and the path forward is not clear. EPRI Heat Rate Conference The Heat Rate Conference previously had a solid focus on applying engineering principles to drive operational improvements on the units. Many presentations were made showing methods to investigate and solve complex problems on turbines, air heaters, condensers, boilers, and balance of plant equipment that affected heat rate. While those presentations were evident at the conference, many more projects were discussed that had a focus more on operational excellence for heat rate improvements. This focus was driven by the continuing debate about global warming and the green house gas emissions from fossil fueled boilers. One presenter made the point that while long-term development work was underway to deal with the emissions, the only thing the existing plants could do now is improve heat rate. Utilities are moving to address these issues in the most cost effective means possible. Reinhold Environmental NOx Roundtable At the NOx conference the focus also changed. At the conference in 2008, the total focus was what needed to be done to allow year-round SCR operations. That has now been achieved with almost everyone running their SCRs continuously. Companies such as Dominion, Duke, Southern, AEP, and others made presentations and held discussions about the procedures currently implemented to test, maintain, clean, and operate the units under the current scheme. Functions, such as catalyst sampling and testing which were easy when the units were only run for five months, are now much harder. Most companies are using forced outages to do this type of work, but others have implemented yearly outage schedules specifically for the SCR work and have found this to be a valuable approach. In addition to this year's focus on what has been done to enable year-round operations, there was also a stronger focus on what can be done to reduce the costs associated with such operations such as reducing the amount of NOx inlet to the SCRs. This shift is a definite sign of progress. A Coming Train Wreck? Despite the advances, the most significant thing I observed across the two conferences was the uncertainty attendees were feeling about regulations facing the industry. A term I heard several times was the "train wreck" that is going to occur by 2015. There is not enough time to achieve the objectives of the proposed regulations and many if not most of the details have not yet been finalized. You could sense that everyone felt there was no way the utilities could supply the electrical needs of the country without running the coal-fired units for the foreseeable future and the costs of some of the proposals were so big that they were impractical. The best example of that is the carbon capture and sequestration (CCS) project currently underway at AEP Mountaineer. The pilot project has been running for over a year with good results. AEP in a joint project with the DOE is currently planning a commercial scale project that will process approximately 20% of the flue gas from the plant. The estimated cost of this project is $686 million with DOE funding half. While there are probably some economies of scale and other cost reductions possible, for just Mountaineer to process 100% of the CO2 from the plant would cost around $3 billion. That is not viable for the coal fleet. Longer-Term View How do you summarize the current plans? The keynote address at the NOx Conference was given by Mr. Chris Hobson, Chief Environmental Officer at Southern Company. Southern has several projects underway including building an IGCC plant and two new nuclear units, implementing a CCS project, and replacing two coal units with new combined cycle plants. Mr. Hobson was asked after his talk if 2015 was such a mess, what about 2030 or 2040. He said he would give the easy answer first: build more nukes and gas-fired plants to serve the needs. He then stated that the problem with this approach was no one knew really what the long-term costs of gas would be. The difficult answer he gave was to do whatever was needed to make the coal units viable. This, he thought, was the best approach since using a diversity of fuels was critical to providing flexibility as changes occur. While most people in the US are not thinking now about implications of these decisions, I suggest we are involved in the most critical industry for our continued well being. I am sitting in a warm office at this moment. The outside temperature is about 10ºF and I can afford to run my heat pump and the power is available to run the unit. Will all those things always be true? Time will tell. Full Blog Post: www.neuco.net/blog

EPA's New CO2 Rules Move Efficiency to the Forefront

Thu, 20 Jan 2011 08:27:00 -0600

The US EPA's New Source Review rules for CO2 quietly went into effect last week. Many people believe this rule is focused on new plants and are waiting for the prescriptive standards to be published this July to gauge the impact of the EPA's Endangerment Finding on existing plants. A more careful look, however, suggests that the regulations that just went into effect have significant implications for existing plants.

With these regulations, modifications made to existing plants that result in a greater than 75,000 tons per year increase of CO2 will become subject to Permits of Significant Deterioration (PSD) and Title V. This 75,000 ton per year CO2 threshold that triggers an NSR for existing units is equivalent to a 1.4% heat rate degradation for a 600 MW coal-fired unit. If you think about the number of changes that could degrade heat rate -- low-NOx burners, SCRs or FGDs, fuel changes, tightened state CO limits, etc. -- you can see how valuable it could be to do everything possible to compensate for such degradation and avoid the costly litigation associated with being served with an NSR lawsuit.

One way this new addition to NSR triggers resembles those for SO2 and NOx is that the litigation will be time-consuming and costly. The vast majority of plants served with NSR suits for NOx and SO2 ended up settling with the EPA and other parties (mostly environmental groups). I expect that the same incentives to settle will play out with CO2 NSR cases, simply because the associated litigation is so costly and disruptive.

What will differ however -- at least in the near-term -- will be the scope and nature of the remedies, whether agreed on through settlement with a consent decree or imposed through an EPA Best Available Control Technology (BACT) finding. The reason is that currently the only commercially-available means of reducing CO2 emissions from fossil-fired generation are to either improve the efficiency of generation or curtail it.

Consistent with this reality, many observers believe that the only thing the EPA will politically and practically be able to impose through BACT will be measures that increase the efficiency of generation, or "Supply-Side Management." The EPA has recently published several white papers that summarize readily available information on control techniques and measures to mitigate greenhouse gas (GHG) emissions from specific industrial sectors. These white papers are intended to provide basic information on GHG control technologies and reduction measures in order to assist States and local air pollution control agencies, tribal authorities, and regulated entities in implementing technologies or measures to reduce GHGs under the Clean Air Act. This particularly relates to permitting under the prevention of significant deterioration (PSD) program and the assessment of best available control technology (BACT).

The document focusing on coal-fired generation is entitled "Efficiency Improvement Technology Description and Reported Efficiency Increases for Existing Coal-Fired EGUs." As a testament to the limited commercially-available alternatives, the document describes just six potential mechanisms for remediation, including: 1) Combustion Control Optimization; 2) Cooling System Heat Loss Recovery; 3) Flue Gas Heat Recovery; 4) Low-rank Coal Drying; 5) Sootblower Optimization; and 6) Steam Turbine Design.

As a provider of Combustion and Sootblower optimization software, I am clearly pleased to see the inclusion of those two methods of remediation. I have seen over and over again during the past dozen years the impact these technologies can have on reducing heat rate through improved boiler efficiency, improved temperature control, improved consistency of operations and reduced steam wastage. Other advantages of these software-based approaches are the substantial co-benefits that can be achieved, such as reduced sootblower-related tube leaks, improved emissions control, better ramping, improved SCR operations, etc.

There is still much to be learned about the impact of the new CO2 regulations in the months ahead as EPA both begins enforcing the new NSR revisions for plants making modifications with heat rate implications and promulgating the new prescriptive standards for all existing plants. But there is little wonder why I’ve already been observing an increased emphasis on heat rate improvement in my recent travels – both at the plant and corporate levels.

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California Again Attempting to Set Precedent on Air Emissions Regulations

Tue, 21 Dec 2010 08:07:00 -0600

The California Air Resources Board (CARB) last week approved a broad economy-wide greenhouse gas cap and trade rule. The CARB vote was 9-1 in favor with no major modifications to the rule. As companies prepare for compliance, purchase and sale of carbon offsets is expected to increase significantly, with the last month entailing active trading and price escalation. The regulation is a key measure to achieve the greenhouse gas reduction goals of AB 32, California's pioneering climate change law signed by Governor Schwarzenegger in 2006. The regulation sets a statewide limit on the emissions from sources responsible for 80 percent of California's greenhouse gas emissions and establishes a price signal needed to drive long-term investment in cleaner fuels and more efficient use of energy. The program is designed to provide covered entities the flexibility to seek out and implement the lowest-cost options to reduce emissions. A novel feature is a benchmarking mechanism designed to allocate a greater number of allowances to the entities within a particular industry segment that are more efficient than their peers, to avoid penalizing companies that took action to reduce their greenhouse gas emissions though improving their efficiency prior to the rule going into effect. The market will cover 360 companies within the state, representing about 600 plants, which including the products of the state's oil refineries, together account for 80 percent of the greenhouse gas emissions in California. The market will price emissions of carbon dioxide, methane and several other greenhouse gases. Each allowance traded on the market will give its holder the right to emit 1 metric ton of carbon dioxide, or in the case of other gases, a physical quantity with the same global warming potential as one ton of CO2. Each allowance will cost at least $10. By 2020, the air board expects prices to range between $15 and $30. Virtually all major California businesses, from pharmaceutical manufacturing facilities to power plants will have to participate in this new carbon market. Trading begins in little more than a year for the first companies included in the market. Businesses will buy and sell allowances - permits to emit greenhouse gases - with the total number of allowances in the market capped by the state. The cap will decline over time, ratcheting down emissions over time. Trading begins in early 2012 for the electricity industry and companies with large industrial facilities. In 2015, the market expands to include companies that sell fuel in bulk. Power plant owners that aren't utilities will have to buy all of their allowances, rather than receiving them free of charge. Investor-owned utilities, such as Pacific Gas and Electric Co., will receive free allowances at first. But the state will require them to sell those allowances and return the money to their ratepayers, possibly in the form of rebates or rate relief. Publicly owned utilities, such as the Sacramento Municipal Utility District, can decide whether or not to auction the allowances they get for free. Along these lines, the rule is explicitly designed so that California may link up with programs in other states or provinces within the Western Climate Initiative, including New Mexico, British Columbia, Ontario and Quebec. Efforts are also underway to link the WCI with other regional climate programs, such as the Midwest Greenhouse Gas Reduction Accord and the Regional Greenhouse Gas Initiative, which covers the power generation emissions of 10 northeastern states. Companies are not given a specific limit on their greenhouse gas emissions but must supply a sufficient number of allowances (each covering the equivalent of one ton of carbon dioxide) to cover their annual emissions. Each year, the total number of allowances issued in the state drops, requiring companies to find the most cost-effective and efficient approaches to reducing their emissions. By the end of the program in 2020 there will be a 15 percent reduction in greenhouse gas emissions compared to today, reaching the same level of emissions as the state experienced in 1990, as required under AB 32. The cap-and-trade program and the other measures to reduce greenhouse gases is explicitly intended to provide a model for action that can be used at the federal, state and regional levels. While I have often critiqued state and regional GHG initiatives in trying to address an inherently global problem that knows no state or national boundaries, there is no doubt substantial precedent for California making policies at the state level that become de facto models for broader federal efforts. This occurred for power plant NOx emissions, automobile fuel efficiency standards, and several other regulatory approaches that have subsequently been woven into the federal legislative and regulatory fabric. As for the precedent-setting of this latest move by the seventh largest economy in the world, we shall have to wait and see. www.neuco.net/blog www.twitter.com/neucoboston

Worry Globally, Act Locally

Mon, 22 Nov 2010 14:42:00 -0600

For better or worse, it looks like the compromise legislation for an electric power-only federal cap & trade system that policy-makers, generation CEOs, and environmental interests alike had hoped for did not survive the hard-ball politics leading up to the recent mid-term elections. Moreover, it is not clear such legislation (mostly recently in the form of the Senate bill sponsored by John Kerry, Joe Lieberman, and -- for a while-- Lindsay Graham) is likely to be reintroduced anytime soon. It could be that such legislation, which has strong popular support, is lit upon by Republicans and Democrats alike as a means of showing an angry electorate that bi-partisan legislation is possible. On the other hand, it may also be the case that there is simply too much partisan rancor to get anything done no matter how much public support. And some people believe that if there is a perceived need for bi-partisan cooperation it will be either something of higher profile or something merely symbolic. Regional Initiatives The lack of federal legislation, however, does not mean that things on the CO2 regulatory front are not changing. For example, the Western Climate Initiative -- after several years of being in legal and political "no-man's land" is now moving expeditiously forward. WCI is an initiative started in 2007 to unite seven states and four Canadian provinces in a giant emissions market by 2012. This has been a tortuous path, however. Arizona has dropped out (but has enacted a state-specific program, as described below). In California the battle over Proposition 23 put the entire initiative in jeopardy. If California had effectively dropped out, New Mexico had hinted it would do the same. But as it turned out, this proposition, purportedly heavily funded by the petroleum industry (whose financial interests differ markedly from power generation on this issue), was roundly defeated by California voters. So as it stands, WCI will now be moving forward on a fairly aggressive timeframe implementing a CO2 cap & trade program for the states and provinces it includes. For example, on November 2nd the New Mexico Environmental Improvement Board enabled the state's participation in the Western Climate Initiative by approving a plan to establish a state-level cap-and-trade program. The state program will begin in 2012 and will affect 63 industrial emission sources, including electric generators. These sources will have to reduce emissions two percent annually until 2020 or obtain from either other market participants or the program administrator a number of allowances (rights to emit) sufficient to cover their emissions. The States Step In There are also a variety of state-specific climate change initiatives affecting fossil-fired power generation outside of the existing regional initiatives. These include Arizona, Illinois, New Hampshire, Oregon, and Virginia. A complete listing of regional and state-specific climate change initiatives affecting generators can be found at the following link: http://www.mwcog.org/uploads/committee-documents/ulZbWF420070928083525.pdf State and Regional Initiative with an International Flare As another example of state and regionally spear-headed initiatives, but with an international dimension, California Governor Arnold Schwarzenegger last week launched an international organization to tackle climate change with leaders from regional governments in Europe, South America, Africa, Asia and the United States. The failure to achieve an international climate pact in Copenhagen last year left many people discouraged, Schwarzenegger said, addressing several hundred delegates at a "climate summit" at UC Davis. But now, he added, "The sub-nationals should do their work... The green revolution is moving forward full speed ahead without the international agreement." Irony Abounds but Hope Remains I've commented on this issue before, but can't help but to highlight the irony in the statement that "sub-nationals should do their work" for a problem that is global by definition. But politics loves a vacuum, and the lack of federal action combined with the widespread popular support for action on climate change is a recipe for a patchwork of regional and state-specific initiatives that will likely be both more costly and less effective than federal action in the context of international accords. While not bullish on the chances that any more rational approach will emerge, there nonetheless remains a chance that a consensus can be forged. Such a consensus would be consistent with the hopes of forward-looking power generation CEOs such as Jim Rodgers from Duke and his colleagues at forward-thinking companies such as NRG, PSE&G and AES, who believe that a consistent price signal should be provided to inform major capital decisions that must be made in the immediate and near-term future. I am skeptical in the short-run, but also believe that the tens of billions of dollars at stake will at some point be sufficient to overcome the partisan rancor and provide a more rational capital investment framework for providing reliable electricity, the greatest single input to our economy and arguably most important component to the infrastructure that we all take for granted in our current way of life. www.neuco.net/blog www.twitter.com/neucoboston