PacifiCorp plans coal retrofits, one coal retirement, in the near term

PacifiCorp plans to convert the coal-fired Naughton Unit 3 to a natural gas-fired facility and to install environmental investments required to meet near term compliance obligations at the Hunter Unit 1, Jim Bridger Unit 3, and Jim Bridger Unit 4 coal units.

“Installation of emission control equipment at these facilities will reduce emissions of nitrous oxides (NOX) and sulfur dioxide (SO2) and contribute to improved visibility in the region,” PacifiCorp added in an integrated resource plan (IRP) filed April 30 at the Utah Public Service Commission. “The Company plans to continue to evaluate environmental investments required to meet known and prospective environmental compliance obligations at existing coal units in future IRPs and future IRP Updates.”

The coal-related action plan includes:

  • Naughton Unit 3 (Wyoming, 330 MW) – Continue permitting and development efforts in support of the Naughton Unit 3 natural gas conversion project. The permit application requesting operation on coal through year-end 2017 is currently under review by the Wyoming  Department of Environmental Quality, Air Quality Division. Issue a request for proposal to procure gas transportation for the Naughton plant as required to support compliance with the conversion date that will be established during the permitting process. Issue an RFP for engineering, procurement, and construction of the Naughton Unit 3 natural gas retrofit as required to support compliance with the conversion date that will be established during the permitting process.
  • Hunter Unit 1 (Utah, 418 MW) – Complete installation of the baghouse conversion and low NOX burner compliance projects at Hunter Unit 1 as required by the end of 2014.
  • Jim Bridger Units 3 and 4 (Wyoming, 702 MW total) – Complete installation of selective catalytic reduction (SCR) compliance projects at Jim Bridger Unit 3 and Jim Bridger Unit 4 as required by the end of 2015 and 2016, respectively.
  • Cholla Unit 4 (Arizona, 387 MW) – Continue to evaluate alternative compliance strategies that will meet Regional Haze compliance obligations, related to the U.S. Environmental Protection Agency’s Federal Implementation Plan requirements to install SCR equipment at Cholla Unit 4.

Regional haze a particular compliance burden for coal units

The state of Utah issued a regional haze state implementation plan (SIP) requiring the installation of SO2, NOx and particulate matter (PM) controls on Hunter Units 1 and 2 and Huntington Units 1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah Regional Haze SIP and disapproved the NOx and PM portions. Certain groups have appealed the EPA’s approval of the SO2 SIP.

In addition, and separate from the EPA’s approval process and related litigation, the Utah Division of Air Quality is undertaking an additional best available retrofit technology (BART) analysis for each of Hunter Units 1 and 2 and Huntington Units 1 and 2, which will be provided to the EPA as a supplement to the existing Utah SIP. It is unknown whether and how the Utah Division of Air Quality’s supplemental analysis will impact the EPA’s approval and disapproval of the existing SIP.

In Wyoming, the state issued two regional haze SIPs requiring the installation of SO2, NOx and PM controls on certain PacifiCorp coal-fueled facilities. The EPA approved the SO2 SIP in December 2012, but initially proposed to disapprove portions of the NOx and PM SIP and instead issue a federal implementation plan (FIP). The EPA proposed to approve the installation of selective catalytic reduction (SCR) equipment and a baghouse at Naughton Unit 3 by Dec. 31, 2014; to approve the installation of SCR equipment at Jim Bridger Unit 3 by Dec. 31, 2015; and to approve the installation of SCR equipment at Jim Bridger Unit 4 by Dec. 31, 2016. The EPA proposed to disapprove the NOx and PM SIP for Jim Bridger Units 1 and 2 and instead accelerate the installation of SCR equipment to 2017 from 2021 and 2022, but agreed to accept comment on maintaining the original schedule as the state proposed.

In addition, the EPA proposed to reject the SIP for the Wyodak facility and Dave Johnston Unit 3 and require the installation of selective non-catalytic reduction (SNCR) equipment within five years, as well as require the installation of low-NOx burners and overfire air systems at Dave Johnston Units 1 and 2. Since the EPA’s initial proposal, which was to have been final in October 2012 and was extended to December 2012, the EPA has withdrawn its proposed action on the SIP and its proposed FIP and has indicated its intent to re-propose action on the Wyoming NOx and PM SIP. In the meantime, certain groups have appealed the EPA’s approval of the Wyoming SO2 SIP which, consistent with the Utah SO2 SIP, required emission reductions of SO2 to be enforced through a three-state milestone and backstop trading program.

In Arizona, the state issued a Regional Haze SIP requiring, among other things, the installation of SO2, NOx and PM controls on Cholla Unit 4, which is owned by PacifiCorp but operated by Arizona Public Service. The EPA approved in part, and disapproved in part, the Arizona SIP and issued a FIP for the disapproved portions. PacifiCorp filed an appeal in the U.S. Ninth Circuit Court of Appeals regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as it relates to their interests.  Other cases are pending before the U.S. Tenth Circuit Court of Appeals with regard to similar appeals of FIPs issued by the EPA in New Mexico and Oklahoma.

PacifiCorp currently anticipates that retiring the 172-MW Carbon plant in Utah in early 2015 will be least-cost alternative to comply with the Mercury and Air Toxics Standards (MATS) and other environmental regulations. PacifiCorp continues to assess other issues, such as potential transmission system impacts, that could impact its ultimate decision regarding the Carbon plant, including the timing of retirement and decommissioning.

Demand side management, a little solar, are key additions in the near term

The key elements of the 2013 IRP include:

  • a finding of resource need, focusing on the 10-year period 2013-2022;
  • the preferred portfolio of incremental supply-side and demand-side resources to meet this need; and
  • an action plan that identifies the steps the company will take during the next two to four years to implement the plan.

The process and outcome of the IRP—the preferred portfolio and action plans—meet applicable state IRP standards and guidelines. PacifiCorp said it continues to plan on a system-wide basis while accommodating state resource acquisition mandates and policies.

Base case wholesale power prices and natural gas prices used in the 2013 IRP are significantly lower than the base case market prices used in the 2011 IRP and 2011 IRP Update. The decline in forward natural gas prices has largely been influenced by continued growth in “prolific” shale gas plays in North America, PacifiCorp noted. With continued declines in natural gas prices and reduced regional loads, forward power prices have also declined significantly over the past two years. Given these favorable market conditions, front office transactions play a critical role in meeting coincident peak loads throughout the initial ten years of the planning horizon.

Policy and market developments have contributed to higher renewable energy costs and reduced benefits. Congressional budget debates make the long-term outlook for federal tax incentives that have traditionally benefited new renewable resources highly uncertain. Federal policy makers have also not succeeded in passing federal greenhouse gas legislation. While EPA has proposed new source performance standards to regulate greenhouse gas emissions from new sources, it has not finalized those standards, nor has it established a schedule to promulgate rules applicable to existing sources. With higher after-tax costs, lower power prices, and continued greenhouse gas regulation uncertainty, the need for new renewable resources will be driven by state-specific renewable portfolio standard (RPS) regulations. To mitigate the cost of RPS compliance, analyses in the 2013 IRP supports the use of unbundled renewable energy credits (RECs) to meet state RPS obligations through the first ten years of the planning period, PacifiCorp said.

Without new resources, the PacifiCorp system experiences a capacity deficit of 824 MW in 2013, down by 57% as compared to the 2011 IRP and down by 39% as compared to the 2011 IRP Update. By 2022, the system capacity deficit reaches 2,308 MW. Over the 2013-2022 timeframe, the system peak load is forecasted to grow at a compounded annual rate of 1.2% (prior to forecasted load reductions from energy efficiency). On an energy basis, PacifiCorp expects system-wide average load growth of 1.1% per year.

As informed by portfolio modeling completed for the 2013 IRP, the company’s action plan focuses on accelerating acquisition of cost effective demand side management (DSM) measures, to take advantage of the risk mitigation benefits of DSM resources by reducing the need for new firm market purchases in the near-term. With policy and market drivers contributing to unfavorable economics for new renewables, renewable resource additions in the 2013 IRP preferred portfolio reflect a near-term unbundled REC compliance strategy. Near-term renewable resources include small scale utility solar resources needed to meet Oregon requirements and distributed solar associated with the Utah Solar Incentive Program. Over the long-term, the 2013 IRP preferred portfolio includes additional wind resources, totaling 650 MW in the 2024 to 2025 timeframe, which contribute to meeting long-term state and assumed RPS obligations.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.