In late March, the Environmental Protection Agency (EPA) proposed its first-ever carbon pollution standard for new power plants, limiting carbon dioxide (CO2) emissions from new fossil fuel–fired power plants to 1,000 pounds/MWh. The standard is achievable for new natural gas combined cycle units without add-on controls, but it would force new coal or petroleum coke units to install carbon capture and storage (CCS) technology, which is currently commercially unavailable, the agency acknowledged. At the same time, the cost of the one integrated gasification combined cycle project under construction in the U.S. rose sharply, again, and more CCS projects are cancelled.
The proposed standard applies only to new gas and coal generating units that are larger than 25 MW. It would not apply to existing units, including those undertaking modifications to meet other air pollution standards, nor to new power plant units that have permits and start construction within 12 months of this proposal. It also would not apply to units in Hawaii and the territories, or to units looking to renew permits as part of a Department of Energy (DOE) demonstration project, provided that those units start construction within 12 months of the proposal.
“We have no plans to address existing plants and in the future, if we were to propose a standard, it would be informed by an extensive public process with all the stakeholders involved,” EPA Administrator Lisa Jackson told reporters on a conference call.
The EPA’s proposed standard reflects the "ongoing trend in the power sector to build cleaner plants, including new, clean-burning, efficient natural gas generation, which is already the technology of choice for new and planned power plants," the agency said. It is also in line with state efforts, such as those implemented in Washington, Oregon, and California, which limit greenhouse gas "pollution," and Montana and Illinois, which require CCS for new coal generation.
"New natural gas combined cycle (NGCC) power plant units should be able to meet the proposed standard without add-on controls," the agency said. "In fact, based on available data, EPA believes that nearly all (95%) of the NGCC units built recently (since 2005) would meet the standard."
For new coal units, which will be required to use CCS or other carbon-mitigating technologies, the agency proposes a compliance option to use a 30-year-average of CO2 emissions to meet the proposed standard, rather than meeting the annual standard each year.
For new coal units, which will be required to use CCS or other carbon-mitigating technologies, the agency proposes a compliance option to use a 30-year-average of CO2 emissions to meet the proposed standard, rather than meeting the annual standard each year. “To the extent market participants have alternative views of both the cost and development of CCS, new conventional coal-fired capacity (or [integrated gasification combined cycle (IGCC)] could be built and operated for some time, with the intention to apply CCS with high removal efficiency at some later date, in order to achieve the required average rate over the 30 year period,” the EPA said.
EPA: CCS Is the “Technology of Choice”
“Carbon Capture and Storage would be the technology of choice; however there are a range of technologies that could be used on both the capture and sequestration side,” EPA spokesperson Cathy Milbourn told POWERnews.
“On the sequestration side, it could range from using captured CO2 for purposes like enhanced oil recovery (which is currently being done in numerous sites across the U.S.) to dedicated sequestration. On the capture side, it can be done using IGCC technology, more traditional pulverized coal technology with post-combustion capture or oxy-combustion with post-combustion capture.”
Some projects in the U.S. have already shown carbon capture gains, Milbourn said, pointing to AES’s coal-fired Warrior Run and Shady Point power plants in Cumberland, Md., and Panama, Okla., which are both equipped with amine scrubbers developed by ABB/Lummus. At Warrior Run, about 110,000 metric tons of CO2 are captured per year, and 66,000 metric tons are captured annually at Shady Point for use in the food processing industry. The EPA also noted American Electric Power’s now-defunct pilot-scale CCS project at Mountaineer using Alstom’s chilled ammonia process, and Southern Co.’s ongoing Alabama Power Plant Barry demonstration project to capture 150,000 metric tons of CO2 annually.
According to the National Energy Technology Laboratory, which tracks existing and proposed U.S. coal-fired power projects, in 2011, five new coal plants totaling 2,343 MW were commissioned. At least 10 other coal plants with a total capacity of 6,619 MW were under construction, and a 320-MW project had obtained all permits and was nearing construction.
Meanwhile, at least 13 plants with a capacity of 8,934 MW were in the permitting phase, and 36 announced projects (11,871 MW) were in the early stages of development. Of the plants that were under construction, permitted, or nearing construction as of January 2012, four had proposed to use pulverized coal subcritical technology; six opted for circulating fluidized bed technology, seven would use supercritical technology, and seven others, IGCC. In comparison, seven announced projects proposed to use subcritical technology while 11 were announced IGCC plants.
CCS could potentially reconcile the widespread use of coal with the need to reduce carbon emissions, but that could be decades away, suggests the International Energy Agency in its November-released World Energy Outlook. "The demonstration phase, which is only just beginning, is likely to last for a decade." At the end of 2010, a total of 234 active or planned CCS projects had been identified, but only five of these demonstrated the full range of capture, transport, and permanent storage of CO2.
Challenges to full-scale demonstration and commercial deployment include high construction costs (assuming an average project cost for a CCS plant of $3,800/kW equates to around $2 billion for a 500-MW plant) and difficulties in financing large-scale projects. "The likelihood is that there will be, at best, no more than a dozen large-scale demonstration plants in operation by 2020," the agency projects.
Asked what carbon-mitigating technologies developers of coal-fired plants could install until CCS becomes commercially feasible—beyond costly precombustion and post-combustion capture technologies—the EPA pointed to “many small actions that can be undertaken, which, cumulatively, can result in notable efficiency improvements.” These include, it said, regular maintenance to sustain optimal operation conditions, maintaining furnace operations near peak efficiency, and ensuring furnace soot removal systems are functioning properly.
Otherwise, generators could switch to “lower-emitting fuels, increased generation share from lower-emitting sources, decreased loss of power via transmission and distribution systems, and improved end-use efficiency lowering electricity demand for the same level of service provided.”
No “Notable Costs”
According to the EPA, the new carbon standard for power plants is “in line” with sector investment patterns, which is why the proposed standard is not expected to have “notable costs” or impact reliability. "EPA, [the Energy Information Administration], and industry projections indicate that, due to the economics of coal and natural gas among other factors, new power plants that are built in the near future will already meet these proposed standards," Milbourn told POWERnews. "Therefore, EPA estimates that there are no additional costs or benefits associated with this proposed rule."
Milbourn pointed to the EPA’s Regulatory Impact Analysis, which says that "even in a baseline scenario without the proposed rule, the only capacity additions subject to this rule projected during the analysis period (through 2020) are compliant with the requirements of this rule (e.g., combined cycle natural gas and small amounts of coal with CCS supported by DOE funding)."
The analysis also says, however, that research into cost and efficiency of varying levels of capture relative to building other energy technologies indicates that lower levels of carbon capture at new coal facilities could be cost competitive, and the costs of meeting the proposed emission rate immediately could be achievable.
"For example, The Clean Air Task Force has compiled data that indicates the levelized cost of electricity for a new supercritical pulverized coal unit with 50 percent CCS (or 1,080 lb/MWh CO2, which is just above the proposed standard) could be $116/MWh compared to $147/MWh for 90 percent removal," it says. "However, investment decisions will be made on a case by case basis dependent upon a number of factors, all of which are difficult to estimate in advance."
An Achievable Rule?
Industry experts generally agree that the rule is unachievable by any coal-fired power plant, absent application of currently unavailable carbon sequestration technology. As Adam Kushner, partner in law firm Hogan Lovells’ Environmental practice and former director of the Office of Civil Enforcement at the EPA, told POWERnews, “EPA’s preamble effectively acknowledges that carbon capture and storage (CCS) is generally not available today. It is for that reason EPA established an emission limit based on a 30-year compliance averaging period. That is, EPA will give new coal plants 30 years to demonstrate they can meet the proposed standard, since the proposed numeric emission limitation for coal-fired power plants is based on a standard currently only achievable by combined cycle natural gas plants,” he said.
“In the preamble to the rule, EPA specifically states that it anticipates that the only way new coal-fired power plants can meet the standard is by carbon capture and storage (CCS) of approximately 50% of the CO2 in the plant’s exhaust gas during start-up or through more effective CCS as it is developed down the road.”
Perhaps the foremost implication of the rule is that it will “effectively halt the construction of new coal-fired power plants. Moreover, the effect of the rule, given the historic low price for natural gas, will be to provide further incentive for coal-fired power owners and operators to continue the trend of converting coal plants to natural gas,” Kushner added.
But the proposed rule won’t be finalized without hiccups, he noted. “EPA will face significant legal challenges to the rule.”
As required by the Clean Air Act for new source performance standards (NSPS) rules, the EPA will need to establish that the emission limit in the rule is “achievable through the application of the best system of emission reduction which . . . has been adequately demonstrated.” For that reason, the “EPA may be hard pressed to show that CCS is adequately demonstrated given its unavailability to many coal-fired power plants. In the face of that specific challenge, EPA will need to justify its reliance on a 30-year compliance standard, which suggests in and of itself that such technology is generally not available today. EPA is also likely to face challenges for predicating the proposed emission standard for coal-fired units on an emission standard EPA acknowledges can only currently be achievable by combined cycle natural gas units.”
Kushner said that several cases related to the EPA’s regulation of greenhouse gases were already being legally challenged. Among these are cases recently argued and fully submitted to the D.C. Circuit Court of Appeals, which challenge, among other things, the EPA’s finding that greenhouse gases threaten the public health and welfare of current and future generations, and the EPA’s “Tailoring” rule, which applies the Clean Air Act’s prevention of significant deterioration (PSD) program to greenhouse gas emissions emitted from both new and existing coal-fired power plants.
“The challenges that are ensuing in the D.C. Circuit will not necessarily impact the proposed NSPS for new plants. However, should the D.C. Circuit reject challenges to the EPA tailoring rule (which is currently in effect), and should EPA’s proposed NSPS be adopted as a final rule, then any PSD permits issued for new plants will have to include an emission limit that is not less stringent than the emission limit in the proposed NSPS for new coal-fired power plants,” Kushner said.
The EPA will accept comment on this proposed rule for 60 days following publication in the Federal Register.
Edwardsport IGCC Project Costs Balloon to $3.3 Billion
Meanwhile, costs for integrated gasification combined cycle technology continue to rise ever higher. On April 27, Duke Energy and some of Indiana’s key consumer groups reached a settlement agreement that resolves a disagreement concerning the utility’s consumer-paid cost overruns for its 618-MW IGCC plant at Edwardsport, Ind. The $3.3 billion coal-fired plant is almost complete and on schedule to begin operations this fall.
If approved by the Indiana Utility Regulatory Commission (IURC), the agreement could end five years of ongoing litigation among the Indiana Office of Utility Consumer Counselor (OUCC), the Duke Energy Industrial Group (which consists of six of the utility’s large industrial customers), Nucor Steel, and Duke Energy.
A joint intervenor group, consisting of the Citizens Action Coalition, Sierra Club, Save the Valley and Valley Watch, is not part of the settlement.
The OUCC, a state agency that represents Indiana consumer interests before state and federal bodies that regulate utilities, said in a statement it has supported construction of the Edwardsport project since 2007 and still supports the plant’s completion. The agency’s disagreements with Duke have focused on cost overruns and inaccurate cost estimates in its testimony in various phases throughout the case, and whether ratepayers or shareholders should bear those costs.
The original project estimate was $1.985 billion; Duke Energy now estimates current plant costs at $3.3 billion, including financing charges. Indiana law allows Duke Energy to increase customer rates incrementally to recover such costs for the Edwardsport project.
But the agreement reached puts a cap on project costs to be included in electric rates at $2.595 billion, which includes estimated financing costs through June 30, 2012. “If a commission order placing the project into customer rates comes after June 30, Duke Energy Indiana will be able to recover additional financing costs until customer rates are revised.” Duke Energy said in a statement.
Under the agreement, construction costs paid by Duke Energy customers will increase by $94 million over the amount the IURC approved in 2009, but it is about $660 million less than Duke Energy’s new construction cost estimates, the OUCC said. “The financing costs capped under the agreement are a portion of the financing costs that have continued to accrue since the 2009 order and would have been otherwise recoverable by Duke in due course under the project as allowed by Indiana law,” it added.
Customers will not pay the full cost of the project, Duke Energy said. “Overall customer rates will rise, on average, an additional 9.6 percent above the approximately 5 percent already in rates. The increase will be implemented over two years (3.2 percent upon settlement approval and then a 6.4 percent increase in mid-2013). Without the settlement, the project would have increased customer rates by approximately 22 percent, compared to approximately 14.5 percent as a result of this agreement.”
“This agreement is the result of countless hours of hard-nosed negotiations with Duke Energy and other consumer parties,” said Indiana Utility Consumer Counselor David Stippler. “While this is an extremely complex case and has been very difficult to resolve, the agreement will require Duke Energy and its shareholders to pay for an appropriate share of the Edwardsport project, while putting an end to the cost overruns and making sure the project goes online for the benefit of Duke’s customers.”
Duke Energy also agreed to a two-year moratorium on any Indiana base rate increases. “Specifically, the utility will be barred from initiating any new base rate case with the IURC before March 2013, and not allowed to implement any increase from such a case before April 2014,” the OUCC said. “Without this provision, Duke would be allowed under state law to seek a base rate increase at any time.”
Under the agreement, the Edwardsport plant’s assets will be valued at the capped costs for the life of the project, and Duke and its shareholders will pay $2 million to the Indiana Utility Ratepayer Trust. Duke shareholder funds will also pay the legal fees for other consumer parties that are part of the agreement and bear all costs for the company’s lawsuits against GE, Bechtel, or other project vendors or contractors. At the same time, the settling parties agree not to oppose or undermine Duke’s legal actions.
"If approved, this agreement achieves two important objectives: It reduces what Duke Energy Indiana customers will pay for an advanced technology power plant, and it resolves uncertainty for Duke Energy shareholders," said Duke Energy Indiana President Doug Esamann.
"We’re now in the home stretch of completing a facility that will modernize our electric system and provide Indiana with cleaner power to meet increasingly strict federal environmental regulations," he added.
Canadian CCS Demonstration Project Plug Pulled
At the end of April, Canadian energy firms TransAlta, Capital Power, and Enbridge scrapped plans for the much-watched Project Pioneer, a joint effort the companies were to undertake with the Canadian federal government and the Province of Alberta to demonstrate commercial-scale viability of carbon capture and storage technology (CCS).
The C$1.4 billion (US$1.42 billion) Pioneer Project would have captured a megaton of carbon dioxide emissions every year for a decade from TransAlta’s Keephills 3 coal-fired power plant in Alberta, and was due to be complete by 2015.
According to the Project Pioneer website, the companies determined that, “although the technology works and capital costs were in-line with expectations, the market for carbon sales and the price of emissions reductions were insufficient to allow the project to proceed.” The decision to shelve the project was reached after a front-end engineering and design (FEED) study was conducted—the first step and an essential part of a project to prove the technical and economic feasibility of any technology before making any major capital commitments.
“Our decision was essentially based on the fact that we could not see a way to make the economics of our CCS project work as we originally intended,” said Don Wharton, vice-president of policy and sustainability at TransAlta. The companies had counted on the development of pure carbon markets, or a government-implemented emissions trading program, neither of which materialized.
Canada’s federal government is instead finalizing rules that could force utilities to shutter coal-fired facilities approaching the end of their 45-year life spans, or the end of their power purchase agreement, if that were later. The so-called “cap and close” regulation would prohibit companies from making investments to extend the lives of those plants unless greenhouse gas (GHG) emission levels could be reduced to those of natural gas combined cycle plants. Projects completed before 2014 would be allowed to operate until the end of their economic lives, under the rule.
TransAlta was to receive C$779 million in federal and provincial funding over 15 years for the CCS project as part of strategies by Ottawa and Alberta to reduce carbon emissions. More than $430 million of that money came from Alberta.
“While we are disappointed that Project Pioneer will not go ahead, we now know the technology works and we still believe there is a future for CCS,” said TransAlta CEO Dawn Farrell.
“Our government continues to invest in a number of projects that are advancing across the country and we will continue research and development with governments, industry and academia to help advance carbon capture and storage technologies,” Federal Natural Resources Minister Joe Oliver said in a statement.
Project Pioneer is just the latest of a string of CCS project casualties. Last December, Swedish firm Vattenfall cancelled the high-profile Jänschwalde project, a $2 billion CCS demonstration project that it had planned to build and begin operating by 2015 in the German federal state of Brandenburg.
Earlier in the year, as Basin Electric announced that the cost and timing of a proposed CCS project at its Antelope Valley Station in North Dakota had caused the plant’s directors to table the project indefinitely, German utility RWE halted work on an IGCC plant with CCS in Hürth, citing a lack of an “adequate legal basis and promotion of acceptance of the CCS technology by policy makers.”
In October, the UK pulled funding for a postcombustion CCS project being built at the 2,400-MW Longannet power station in Fife, Scotland, by ScottishPower, UK grid operator National Grid, and oil company Shell. And in July, American Electric Power shelved its $668 million CCS project at its 1,300-MW Mountaineer Plant in New Haven, W.Va.—a project that had just completed validation—citing uncertain U.S. climate policy and a weak economy.
Even the U.S. Department of Energy’s FutureGen 2.0 oxy-combustion project now hangs in limbo after Ameren Energy Resources in November pulled out of the venture spearheaded by the FutureGen Alliance. The alliance is negotiating an option to buy portions of Ameren’s Meredosia Energy Center in Illinois to continue development of that project.
—Sonal Patel is POWER’s senior writer. This material was first published in POWERnews.