The Short Term Action Plan of Duke Energy Carolinas, which identifies actions to be taken over the next five years, includes a number of coal unit shutdowns and conversions to natural gas.
The Duke Energy (NYSE: DUK) subsidiary filed its latest integrated resource plan (IRP) with the South Carolina Public Service Commission on Sept. 1.
Because the Duke Energy and Progress Energy merger closed only recently, Duke Energy Carolinas and Progress Energy Carolinas were unable to coordinate their 2012 IRP filings. Input assumptions such as fuel prices, environmental inputs, and generation costs, as well as sensitivities and scenarios were developed independently. Assumptions around key inputs such as Energy Efficiency (EE), Demand Side Management (DSM), renewable resources and CO2 regulation costs will be reconciled in the next planning cycle.
Among the highlights in the Duke Energy Carolinas short-term plan:
- Continue to evaluate and plan for the retirement of older coal generation. Buck Units 3-4 were retired in May 2011. Cliffside Units 1-4 and Dan River Units 1-2 were retired in October 2011 and April 2012, respectively, in advance of the initial testing of new generation at those locations. Retirements of the remaining unscrubbed coal units at Buck, Riverbend and Lee are currently planned for April 2015 to correspond with compliance with the Mercury and Air Toxics Standards. The to-be-retired units and their capacities are: Riverbend Units 4-5 (94 MW each); Riverbend Units 6-7 (133 MW each); Buck Units 5-6 (128 MW each); Lee Units 1-2 (100 MW each); and Lee Unit 3 (170 MW).
- Retire all of its older combustion turbines (CTs) in October 2012, which are at the Buzzard Roost, Riverbend, Buck and Dan River plants.
- Completed construction of the new gas-fired Buck Combined Cycle (CC) unit. The 620-MW unit was operational November 2011.
- Complete construction of the coal-fired, 825-MW Cliffside Unit 6, at the existing Cliffside plant. As of August, the project is in testing phase with commercial operation expected in September. The North Carolina Utilities Commission (NCUC) approval for Cliffside Unit 6 required the retirement of the coal-fired Cliffside Units 1-4 no later than the commercial operation date of the new unit. In addition to retiring Cliffside Units 1-4, the air permit for the new Cliffside unit requires the retirement of 350 MW of older coal generation by 2015, a further 200 MW by 2016, and an additional 250 MW by 2018. “If the NCUC determines that the scheduled retirement of any unit identified for retirement pursuant to the IRP will have a material adverse impact of the reliability of electric generating system, Duke Energy Carolinas may seek modification of this plan,” the IRP noted.
- Complete construction of the 620-MW combined-cycle plant at Dan River Steam Station. As of August, the project was over 90% complete.
- Continue to assess the conversion of Lee Unit 3 from coal to natural gas. This unit is reflected in the 2012 IRP as a retired coal unit in the fourth quarter of 2014 and converted to natural gas by Jan. 1, 2015. Preliminary engineering has been completed and more detailed project development and regulatory efforts are ongoing. Lee was originally designed to burn natural gas or coal. Switching to natural gas now would avoid adding costly pollution control equipment or replacing the 370 MW of capacity with a more expensive alternative. Previous plans were for conversion of all three Lee units to gas. But, upon further evaluation, for IRP planning purposes, Lee Units 1-2 will be retired as coal units with no plans for conversion to gas in 2015.
Changes in assumptions push back capacity need to 2016
The notable changes from the 2011 IRP to the 2012 IRP are a shift in the company’s first capacity need from 2015 to 2016 and lower projected fundamental natural gas prices throughout the planning horizon.
The shift of the first capacity need from 2015 to 2016 is primarily due to lower forecasted load projections, an increase in projected capacity and energy purchases from qualifying facilities (QF), an increase in projected participation in demand side management (DSM) programs, a lower planning reserve margin, as well as changes in the company’s projected compliance portfolio relating to the North Carolina renewable energy requirements. These factors, taken together, result in the company’s first new resource need of 410 MW in 2016.
The increase in projected QF capacity and energy arises from the potential addition of new solar QF facilities and due to the renewal of the 88-MW Cherokee Co-Generation QF contract. The Cherokee contract was due to expire in 2013, but has now been extended through 2020.
The company’s analysis reflects a shift in strategy for North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (REPS) compliance over the long term. In the 2011 IRP, the NC REPS compliance strategy relied primarily on wind and biomass resources during the first 10 years and a shift to primarily biomass resources for the remainder of the planning period. Based upon the increase in recent proposals for solar QF facilities, for the 2012 IRP, Duke’s strategy has shifted from a reliance on biomass to a greater reliance on solar resources. Even though solar facilities have a lower contribution to the company’s peak than biomass resources, the projected increase in volume of solar QFs results in a net increase of renewable resources available to meet peak demand requirements in 2015 of approximately 40 MW.
As part of the North Carolina Utilities Commission approval of the utilities’ respective 2010 IRPs, Duke Energy Carolinas and new sister company Progress Energy Carolinas were ordered to perform a quantitative analysis of the respective reserve margins and to provide the study results in the companies’ 2012 IRPs. Based on the results of this analysis, Duke Energy Carolinas utilized a target Planning Reserve margin of 15.5% in the 2012 IRP. This is a reduction from a 17% target Planning Reserve margin used in the 2011 IRP, which resulted in approximately 200 MW of reduced capacity need in 2015.
Duke says cheap gas doesn’t undermine nuclear planning
Due to the lowered natural gas price projections, the 2012 IRP found that the 2016 resource need would be served most cost-effectively by combined cycle resources instead of by the combustion turbine resources identified in the 2011 IRP.
Despite the lower projected natural gas prices, on a long-term basis, Duke Energy Carolinas’ analysis continues to support a robust portfolio including new nuclear, CC and CT generation resources. Thus, in the 2012 IRP, portfolios consisting of new nuclear and gas generation remain competitive with portfolios where all intermediate and base load needs are met with natural gas resources.
Without new nuclear generation, CO2 emissions for the natural gas portfolio are projected to continue to rise throughout the planning period. In addition, the company’s fundamental natural gas prices were developed assuming continued operation of the nation’s existing nuclear fleet. The operating licenses of many of the country’s existing nuclear units have already been extended and will expire within the planning horizon. If these units are replaced with natural gas-fired resources, the result would be a projected increase in natural gas prices.
Although greenhouse gas (GHG) legislation is not believed to be imminent, the U.S. Environmental Protection Agency continues to pursue CO2 regulations on existing and new generation units, the IRP noted. For these reasons, among others, the company believes it is prudent to continue to preserve the option for new nuclear generation in combination with new CC and CT resources.
In 2011, Duke Energy Carolinas’ nuclear and coal-fired generating units met the vast majority of customer needs by providing 52.2% and 45.7%, respectively, of the company’s energy from generation. Hydroelectric generation, CT generation, solar generation, long term power purchase agreements (PPAs), and economical purchases from the wholesale market supplied the remainder.
Duke pursues new coal blends at scrubbed power plants
In an IRP section on fuel supply, the company noted that until the economic downturn in 2008, it had burned approximately 18 million tons of coal annually. In 2009, the burn dropped substantially and has remained in the yearly range of 14 million to 16 million tons of coal. The projected coal burn for the near-term is declining further due to lower gas prices, the addition of the Buck CC plant, more stringent environmental regulations on coal units, and lower load growth.
The company continues to procure coal primarily from Central Appalachian (CAPP) mines that is delivered by the Norfolk Southern and CSX railroads. Although CAPP coal market prices are currently below the marginal mining costs for many mines, due to the unseasonably mild 2011-2012 winter and the resulting low gas prices, CAPP prices are projected to recover over the next couple of years, the IRP noted. Longer term, CAPP prices are expected to rise due to declining quality of CAPP coal reserves, increasingly stringent safety requirements, and longer and increasingly difficult environmental permitting for CAPP mines.
For this reason, the company has been testing Northern Appalachian (NAPP) and Illinois Basin (ILB) coals at its scrubbed stations. These tests will continue and will provide valuable information on operational and environmental impacts of burning these coals in various blends. This information will assist the company in determining which coal blends can be burned without requiring additional capital investment, as well as the capital investments required to consume even greater amounts of non-CAPP coal. “The purpose of this work is not to lock the Company’s plants into new fuel types, but to increase the fuel flexibility of each station so that the Company can nimbly respond to changes in the relative coal prices of different coal types,” the company added.
Despite gas production cutbacks lately due to the low gas prices, once again the U.S. is on course to set another record in total marketed U.S. production of natural gas, Duke said. The production cutbacks have managed to stabilize the wholesale gas prices at around $2.50-$3.00/mmbtu for now,but they are not likely to push prices significantly higher in the near term.
Even with new supplies of gas from shale plays, gas should still be viewed as a bridge fuel, rather than a final solution, Duke said.