Idaho Energy Update
December 7, 2011
Idaho Power relies on out-of-state coal-fired power plants for more than 40 percent of its electric generation. As part of its required power planning process the utility says it will examine each of the coal plants in which it has an interest to determine whether to continue the massive investments required to keep the plants legal, or whether to begin planning to retire them and replace their generation with cleaner resources. Meanwhile, the state’s largest electric utility has filed contracts with regulators for three new renewable energy projects – including wind, small hydro and landfill gas generation. Speaking of hydropower, Idaho Power has reported to the PUC that its costs to date in the seven-year-old Hells Canyon hydropower relicensing saga have eclipsed $141 million, and the case is a long way from resolution. For more information on these developments and coming events, read on. Thanks as always, and if you have any calendar items, please send them along!
Clean Energy Program Director
Snake River Alliance
I: Idaho Power Says It Will Take Close Look at Coal Fleet
Idaho Power Co. says it will conduct a detailed analysis of its coal-fired generation assets as it prepares to begin its next Integrated Resource Plan (IRP), which the company will submit to utility regulators in 2013.
Idaho Power filed comments to the Idaho Public Utilities Commission (PUC) on Nov. 28, responding to earlier comments submitted by the Snake River Alliance (SRA), Idaho Conservation League (ICL), and Renewable Northwest Project (RNP), all of which recommended that the PUC require the utility to fully analyze the coal plants in which the company has an interest. In particular, the conservation groups want the company to study whether coal plants at the Bridger complex in Wyoming and the North Valmy complex in Nevada might be candidates for early retirement rather than investing millions of ratepayer dollars to keep the plants in compliance with increasingly stringent state and federal environmental regulations.
Utility IRPs are prepared every two years and are intended to serve as roadmaps on how utilities plan to meet future electricity demand. Among other things, the IRPs outline a utility’s plans to add new generation resources as well as additional energy efficiency and conservation measures. In its comments, Idaho Power notified the PUC that it will undertake an analysis of the coal plants in Wyoming and Nevada. Idaho Power does not operate the plants, but is a one-third partner in the Bridger coal plants and a half owner of the plants in Nevada. Combined with Idaho Power’s 10 percent share of the Boardman coal plant in Oregon, which is now slated for early retirement by about 2020, coal generation accounts for more than 40 percent of Idaho Power’s generation portfolio. Most of the rest comes from hydropower facilities such as Idaho Power’s Hells Canyon complex.
“The ICL, SRA and RNP all provide comments suggesting the Company include more detailed analyses related to the costs and risks associated with its fleet of coal generation considering potential carbon costs and environmental regulations,” Idaho Power wrote in its comments to the PUC. “Of note, many of the pending environmental regulations that could apply to the Company’s coal fleet are largely unknown at this time. That said, Idaho Power currently anticipates that some key regulations will be further developed in 2012 such that the Company anticipates conducting a unit-by-unit environmental compliance cost analysis on its coal fleet in 2012.”
Idaho Power says it will hire third-party consultants to perform the study “in conjunction with studies conducted by the majority owners/operators of the coal plants as well as internally generated analyses to evaluate environmental compliance costs associated with its coal plants.” Those studies will be done next year as the company prepares for its 2013 IRP, which will begin in the middle of 2012. “The Company looks forward to working with ICL, SRA, RNP, and other interested parties through the Integrated Resource Plan Advisory Council on these coal cost issues in preparing its 2013 IRP.” PacifiCorp, which does business in southeast Idaho as Rocky Mountain Power and which is the majority owner of the Bridger coal plants, is conducting a similar analysis for regulators in Oregon.
The PUC will likely decide whether to “accept” Idaho Power’s 2011 IRP early next year. To review the IRP and related documents, including comments by various parties and individuals, go to www.puc.idaho.gov and then to “File Room” and then “Electric Cases” and scroll to IPC-E-11-11.
II: Idaho Power Submits Contracts with Renewable Energy Developers
Idaho Power has submitted to the Public Utilities Commission contracts to purchase energy from three separate renewable energy developers – including a wind project, a small hydropower project, and a landfill gas generator. The contracts were filed under the 1978 Public Utility Regulatory Policies Act (PURPA).
The utility has asked the PUC to accept or reject its contract with High Mesa Energy, which plans to develop a wind project near Bliss that could generate up to 40 megawatts of power. Unlike the wind projects that are currently held up at the PUC due to disagreements over their size and the cost of their energy, this project is different in that the amount paid to the wind farm developer would be based on an alternate method of setting the rates. High Mesa expects to begin generating from the wind farm by the end of 2012. Idaho Power and High Mesa will share the costs of wind forecasting and also the valuable “renewable energy credits” (RECs, also known as “green tags”) that are the environmental attributes from the renewable energy resource.
Idaho Power has also submitted for PUC review a contract with Eagle-based Dynamis Energy, which is proposing to build a landfill gas generator at the Ada County Landfill in Boise. Idaho Power is already buying electricity from other landfill gas generators at the Ada County facility, and this one by Dynamis would generate 22 megawatts, far greater than the amount produced from two other landfill gas-to-energy plants at the site. In the past, the gas resulting from decomposing garbage has been flared off. Dynamis plans to begin producing energy in October 2013. Idaho Power and Dynamis will also share the RECs from the project during the 20 years covered by the contract.
Finally, Idaho Power has submitted a contract with Riverside Investments to purchase the power from Riverside’s proposed 1.27 megawatt Fargo Drop small hydropower generator near Homedale. Riverside expects to begin producing power from the facility in July 2012. Both parties will also share the RECs from the project.
To review these contracts and other documents in the cases, go to www.puc.idaho.gov and then to “File Room” and then “Electric Cases” and scroll to IPC-E-11-25, IPC-E-11-26, and IPC-E-11-27.
III: Idaho Power: Hells Canyon Relicensing Cost is $141 Million and Counting
Idaho Power says it has spent $141 million so far in its eight-year effort to relicense its Hells Canyon Complex, which includes the Brownlee, Oxbow, and Hells Canyon dams, which at 1,167 megawatts of generation comprise the company’s largest power generation resource.
Idaho Power has been pursuing the relicensing of the Hells Canyon Complex (HCC) with the U.S. Federal Energy Regulatory Commission (FERC) and other state and federal agencies since 2003. As part of its 2008 general rate case, Idaho Power agreed to file periodic status reports with the Idaho Public Utilities Commission (PUC) to keep regulators abreast of the process and the costs the company and its customers are incurring as part of the hydropower relicensing effort. In an earlier order, the PUC referenced the relicensing costs as building to “alarming levels.”
Eventually, the costs associated with relicensing the dams will be included in rates paid by Idaho Power customers. Currently, only small portions of the costs are being recovered through customer rates.
“Idaho Power considers the HCC relicensing project to be a viable, cost-effective effort that will ultimately serve the best interests of customers,” the company wrote in its latest status report to the PUC, which must approve utility expenditures before they can be included in rates and recovered from customers.
The Hells Canyon relicensing process is profoundly complex, which is one reason why it has dragged on for so many years. Even before filing for its HCC license renewal in 2003, Idaho Power said it spent about $45 million on 200 stakeholder meetings and more than 100 relicensing studies to prepare for the relicensing. The relicensing application alone consists of more than 35,000 pages. Twenty-seven parties filed motions to participate in the case, including four Native American tribes. Key issues in the case deal not only with the power generation from the dams, but also myriad environmental and recreation issues and how to deal with some of the dams’ environmental impacts.
Besides dealing with the regulatory issues governed by FERC, Idaho Power must also navigate a complicated environmental process that includes measures to mitigate the hydropower complex’s impacts on downstream fish and wildlife. The case is also complicated by the fact that the HCC straddles two state borders (Idaho and Oregon) and is above federally protected salmon and bull trout species, the federal Hells Canyon National Recreation Area, a 70-mile stretch of the Snake River that’s designated as “wild and scenic” under the Wild and Scenic Rivers Act, and has impacts on two national forests as well as lands managed by the U.S. Bureau of Land Management. If things go as planned – and so far not much has in this case – Idaho Power anticipates the relicensing process might be concluded sometime in 2014. Since the prior FERC license expired in 2005, Idaho Power and its HCC have been operating under one-year licenses issued by FERC.
For information on Idaho Power’s 2008 rate case, including the Hells Canyon status report to the PUC, go to www.puc.idaho.gov and then “File Room” and then “Closed Cases” and scroll to IPC-E-08-10.
On The Agenda:
► The Public Utilities Commission will hold public hearings Thursday, Dec. 8 and Monday, Dec. 19 to receive testimony in the PacifiCorp’s general rate case. The Dec. 8 hearing will be at the Fremont County Annex Room in St. Anthony. The Dec. 19 hearing will be at the PUC’s Boise headquarters at 472 W. Washington St. Both begin at 7 p.m. The PUC will also conduct a technical hearing in the case beginning on Dec. 19 and running through Dec. 21 if necessary. That meeting will also be held at the PUC’s Boise headquarters. PacifiCorp, which does business in Idaho as Rocky Mountain Power and which serves customers in southeast Idaho, reached a settlement agreement with several parties to reduce the size of the proposed rate increase from an average 15 percent to an average 7.8 percent in 2012 and 7.2 percent in 2013. The company agreed not to seek another rate hike until 2014. To review documents in the case, go to www.puc.idaho.gov and then “File Room” and then “Electric Cases” and scroll to PAC-E-11-12.
► The Public Utilities Commission holds its next decision meetings on Dec. 14 and 21. Agendas are normally posted the day before on the Commission’s website at www.puc.idaho.gov The meetings typically start at 1:30 p.m.