AT THE MAJOR CCS PROJECTS: KEMPER, QUEST, TAYLORVILLE, HECA

Tamar Hallerman
GHG Monitor
07/13/12

AT KEMPER: MISS. POWER SEES MORE COST OVERRUNS, FILES SUIT

Mississippi Power continues to face an uphill battle politically in order to get its 582 MW Kemper County integrated gasification combined cycle plant built on schedule and on budget, with a new report this week indicating that the project has already hit its ‘hard’ rate recovery cap. The Sierra Club this week released the utility’s most recent monthly progress report, which was submitted to URS Corp., the project’s independent monitor hired by the state Public Service Commission (PSC). That update indicates that the project is now estimated to cost $2.88 billion, about $6 million above the ‘hard’ rate recovery cap affirmed by the PSC earlier this spring, according to the environmental group. The announcement marks the third project cost increase in as many months for the project, whose construction is roughly 31 percent complete, according to Mississippi Power. Kemper is now $484 million above the project’s initial cost estimate of $2.4 billion.

While Mississippi Power spokesman Jeff Shepard would not confirm the $2.88 billion cost figure to GHG Monitor, he said that the utility is committed to keeping project costs down. “Construction projects, especially ones of this size, are going to have cost fluctuations,” he said. “Our intent is to be within the $2.88 billion cost cap as issued by the Public Service Commission. Even with these updated costs, we are still within the cost cap. Every day Mississippi Power works to ensure we bring this plant online within the cost cap.” Also known as Plant Ratcliffe, Mississippi Power plans on capturing roughly 65 percent of CO2 emissions onsite for use in nearby enhanced oil recovery operations. The project has been under construction in eastern Mississippi for the last two years and is expected to come online in spring 2014.

Louie Miller, director of the Mississippi chapter of the Sierra Club, told GHG Monitor that he expects project costs to continue creeping up over the course of plant construction “without question.” “That is not going to slow down—this is obviously spiraling out of control,” he said. In a subsequent statement, he said that Mississippi Power is “not telling the public the whole story” about project costs. “This new cost report from Mississippi Power is proof positive that the company has continued to sugarcoat the cost of this project, misleading the Public Service Commission and the ratepayers as to its true impacts,” Miller said.

Moody’s Mulls Credit Rating Downgrade for Miss. Power

The announcement will likely impact the utility as the credit ratings agency Moody’s Investors Service mulls its rating in the weeks ahead. Moody’s announced earlier in the week—before the additional cost overruns were announced—that it would be putting the utility’s credit rating on review for a downgrade mainly due to the PSC’s denial of a $55 million rate increase for the project last month. Moody’s said that inability to recover financing costs will “further stress already weak financial metrics” and could lead to higher rate increases for the utility’s customers once plant construction wraps. “The review of Mississippi Power’s ratings reflects the significant decline in the company’s cash flow coverage metrics as a result of the construction of the $2.88 billion Kemper County integrated coal gasification combined cycle plant,” Moody’s said in a release.

Moody’s announcement marks the second time this month that Mississippi’s credit rating has been put in jeopardy. Last week, the agency Fitch Ratings downgraded the utility’s credit rating from an ‘A’ to an ‘A-’ and revised its ratings outlook from ‘stable’ to ‘negative,’ also citing project cost overruns and the PSC decision. At the time, Mississippi Power warned that if more credit rating groups also downgrade the utility’s rating, borrowing rates could and the company’s access to credit could be put in jeopardy.

Miss. Power Appeals Rate Ruling to Supreme Court

Meanwhile, earlier this week Mississippi Power filed an appeal to the state Supreme Court in a bid to invalidate a recent order from the PSC denying the project a $55 million rate increase to help pay for construction costs. On June 22, the PSC voted unanimously to deny the utility a six-month rate increase from its nearly 200,000 customers to help pay for the IGCC plant under the Construction Work in Progress (CWIP) program. In an order, the commissioners said it would not be prudent to issue any rate increases until a legal challenge from the Sierra Club becomes resolved. “This legal action, which includes a motion for interim rate relief, is necessary to save customers millions of dollars in interest costs,” Mississippi Power said in a company statement released earlier this week. “Timely recovery of financing costs is critical to the company’s ability to maintain financial health and have access to capital needed in its everyday operations as well as in emergency situations when customers need it most.” 

AT QUEST: PROJECT GAINS PRELIM PROVINCIAL REGULATORY APPROVAL

Alberta regulators conditionally approved Shell Canada’s $1.35 billion Quest carbon capture and storage project this week, helping the venture clear one of its final regulatory hurdles before backers will make a final decision on whether to ultimately move forward with construction. Alberta’s Energy Resources Conservation Board (ERCB) concluded this week that the project is in the public interest. “The hearing panel determined it is in the public interest to proceed with the project, noting the proposed reservoir is a suitable location for the long-term storage of carbon dioxide and the combination of geological conditions, engineering design, operational practices, and extensive monitoring program mitigate any potential risks the project might pose,” ERCB said on its website.

ERCB said that the project, slated for an area northeast of Edmonton, now needs to be reviewed by the Alberta Ministry of Environment and Sustainable Resource Development before it can gain final provincial regulatory approval. The Board also gave Shell 23 conditions it must agree to before work on Quest can begin—most focusing on additional data collection, analysis and reporting. The regulators, which held a hearing on the project earlier this spring, said that Shell must also seek separate approvals for any project additions.

Final Investment Decision Still Upcoming

A Shell Canada official said that the company was “delighted” by the decision. “This is a really important and exciting milestone for the project and takes us one step closer to implementing the first carbon capture project for an oil sands operation,” said John Abbott, Shell’s vice-president of heavy oil in a company statement. In the meantime, the company is still completing feasibility studies in the lead up to a final investment decision with project partners Chevron Canada and Marathon Oil expected later this year.

Project partners plan on retrofitting Shell’s Scotford Upgrader in central Alberta, which processes bitumen, or heavy crude oil, from the province’s nearby Athabasca oil sands with post-combustion technology that would capture up to 1.2 million tons of CO2 per year. The project then plans on storing the CO2 at a saline aquifer approximately 50 miles north of the upgrader beginning in 2015, if all goes according to schedule. Last summer, the Alberta and Canadian governments officially committed $865 million in provincial and federal dollars to the project over a 15-year period, the funding of which will likely account for roughly five years of upfront capital costs as well as the first decade of the project’s operation, Shell officials previously told GHG Monitor.

Quest will likely face significant pressure to move forward in the months ahead within the fossil-fuel rich province of Alberta, which has invested $2 billion of its own funds into developing four CCS projects. However, this spring electricity generator TransAlta Corp. announced that it would be abandoning plans for its $1.4 billion Project Pioneer due to what it says was the inability to secure suitable contracts for captured CO2. The other two projects being funded by the provincial government, Swan Hills Synfuels and the Alberta Carbon Trunk Line, are also considered promising but both are further behind in the regulatory process than Quest.

AT TAYLORVILLE: ILLINOIS EPA TO RECONSIDER AIR PERMIT

The Illinois Environmental Protection Agency (IEPA) this week withdrew the air permit it issued to Tenaska Energy’s Taylorville Energy Center earlier this spring, announcing its plans to reconsider the proposal using ‘best available control technologies.’ In a filing submitted earlier this week to the federal EPA’s Environmental Appeals Board, IEPA said it will—in a rare move—reconsider the permit due to comments it received from environmental groups and the EPA in the week’s following the granting of its initial permit for the 602 MW project.

Earlier this spring, IEPA issued an air permit for the $3.5 billion hybrid coal gasification and natural gas combined cycle facility without including a carbon capture and storage requirement. In its explanation of the permit, IEPA said it did not include a limit on greenhouse gas emissions because a mandate would be too difficult to enforce and inconsistent with the state’s best available control technology determination. In the past, Tenaska had said publically that it planned on capturing and sequestering emissions. In the weeks that followed, the Natural Resources Defense Council and the Sierra Club filed an appeal to EPA’s Environmental Appeals Board, arguing that the permit was “legally flawed” because it did not take into account best available control technologies for coal plants such as CCS. Meanwhile, U.S. EPA Region 5 Administrator Susan Hedman wrote to IEPA in June asking the agency to also reconsider the permit with a CCS component.

Environmental groups in the state cheered the announcement. “Sometimes it is important to beat a supposedly dead horse, especially when that horse can make bad legal precedent,” NRDC Staff Attorney Meleah Geertsma said in a blog post on the environmental group’s website. “We are pretty confident that the only way the plant can survive the process is to actually do what they claimed all along—deal with the carbon pollution.” Tenaska did not respond to a request for comment.

Project Still Faces Rough Political Future

Ultimately, the move by IEPA could largely be moot given that Tenaska has floated the idea of postponing the coal gasification and carbon capture portions of the project in order to gain political support in the state legislature. However, following several weeks of intense debates, the retooled project failed to see a floor vote prior to the end of the legislative session in May and Tenaska was sent packing from Springfield. It is unclear whether Tenaska will continue pushing the cheaper, natural gas-only plant through the end of the year or whether the utility will choose to move on, as several project officials have said the company would do if it failed to get enough support in the legislature.

AT HECA: DOE, STATE REGULATORS HOLD PUBLIC HEARING ON PROJECT

State and federal regulators held a public meeting July 12 to assess local support for the Hydrogen Energy California (HECA) poly-generation carbon capture and storage project proposed for Kern County, Calif. The project, which is receiving funding from the Department of Energy’s Clean Coal Power Initiative, is being jointly assessed by the department and the California Energy Commission for a permit amendment submitted earlier this summer. The meeting, part of the National Environmental Policy Act process, will ultimately help contribute to the regulators’ decision on whether to grant developers an amended permit for the project.

The gathering represents the most recent step to retool the HECA project after the Massachusetts-based power plant development company SCS Energy LLC formally acquired the rights to the 400 MW integrated gasification combined cycle project from BP and Rio Tinto last year. After taking over, SCS Energy significantly modified original plans for the hydrogen-fueled project slated for a construction 25 miles west of Bakersfield, Calif. SCS added a polygeneration component to sell electricity, urea fertilizer and captured CO2 for enhanced oil recovery use in nearby oil fields. Those changes subsequently caused the price tag for the project to rise from $2.8 billion to $3.9 billion. Earlier this summer, HECA submitted an amendment to the project’s permit application originally administered to BP and Rio Tinto in order to reflect those proposed changes. SCS said that the plant is expected to come online by the end of 2017.