Kentucky Utilities sees possible gas-fired addition after 2018

Kentucky Utilities d/b/a Old Dominion Power put a lot of different scenarios in an integrated resource plan (IRP) filed April 29 with the Virginia State Corporation Commission, in part due to the uncertainty of both the timing and requirements of the U.S. Environmental Protection Agency’s Clean Power Plan.

The commission on May 17 ordered the utility, which has all of its power plants in Kentucky and serves 28,000 customers in southwest Virginia, to put the IRP out for public notice. KU/ODP and sister utility Louisville Gas and Electric, both subsidiaries of PPL Corp. (NYSE: PPL), control about 8,000 MW of generation capacity, most of it coal-fired.

In response to applications for stay by numerous parties, on Feb. 9, the U.S. Supreme Court granted a stay of the Clean Power Plan pending review of the rule at the U.S. Court of Appeals for the D.C. Circuit, and potentially at the Supreme Court itself once the appeals court has ruled.

The Clean Power Plan has two different approaches, KU/ODU noted. It also pointed out that Kentucky, a major coal producer, is one of the staunchest opponents of the plan.

“Concerning a rate-based compliance approach, LG&E-KU’s combined CO2 emission rate in 2012 was 2,112 lbs/MWh, which was slightly below the Kentucky state average of 2,166 lbs/MWh. But the final CPP’s 2030 rate-based target for Kentucky is 1,286 lbs/MWh, 41% less than Kentucky’s actual 2012 emission rate. En route to the 2030 target, though, are several less stringent interim average targets: 1,643 lbs/MWh for 2022-24; 1,476 lbs/MWh for 2025-27; and 1,358 lbs/MWh for 2028-29. To comply on a rate-based approach, LG&E and KU may need to modify their current portfolio of generating assets during the next decade, participate in an allowance trading program, or both. It appears likely that other market-based mechanisms such as a single- or multi-state Emission Reduction Credit (ERC) purchase mechanism may be available for consideration by Kentucky. The precise timing and amount of such changes is unknown, and cannot be known with any reasonable certainty until the compliance plan applicable to Kentucky, and therefore to KU and LG&E, is known. Similarly, the rate impacts of CPP compliance cannot be projected with any accuracy at this time, though eventual rate increases resulting from CPP compliance appear highly likely.

“A mass-based approach, which Kentucky’s Energy and Environment Cabinet currently appears to favor, would require Kentucky to reduce its CO2 emissions from its 2012 level of 91.4 million tons per year (‘TPY’) to 63.1 million TPY in 2030, with interim targets of 76.8 million TPY in 2022-24, 69.7 million TPY in 2025-27, and 65.7 million TPY in 2028-29. Based on the Kentucky’s Energy and Environment Cabinet’s projections of CO2 emissions from electric generation, which show Kentucky’s emissions have been decreasing consistently since 2010, it appears Kentucky may not have to make any major changes to meet a mass-based approach for the first interim target period, i.e., though the end of 2024. Beginning in 2025, though, reductions from projected levels would be necessary. If Kentucky ultimately falls under a mass-based compliance approach, particularly with a single- or multi-state allowance-trading mechanism, it is possible KU may not have to change its current generating fleet significantly to achieve CPP compliance. But as with a rate-based approach, it appears highly likely CPP compliance would result in higher rates for customers due to allowance purchases, capacity changes, or a combination of the two.”

The combination of various other EPA rules, like the Mercury and Air Toxics Standards, has forced the shutdown by the two utilities of several coal units. Cane Run Unit 6 was retired in March 2015, Cane Run Units 4-5 were retired in June 2015 in coordination with the commercial operation of the gas-fired Cane Run Unit 7, and Green River 3-4 were retired in September 2015. No additional retirements are assumed during the 15-year IRP planning period.

To comply with environmental regulations, the companies recently installed fabric filter baghouses on Brown 3, Ghent 1-4, Mill Creek 1, Mill Creek 2, Mill Creek 4, and Trimble County 1. New flue gas desulfurization systems (FGDs) were also installed on Mill Creek 1, Mill Creek 2, and Mill Creek 4. A baghouse and new FGD will be installed on Mill Creek 3 by June 2016. No additional changes to emission controls, operating characteristics, unit ratings, unit availabilities, or fuel supply are assumed for existing units over the planning period.

Nine KU municipal customers provided notices of termination of their wholesale power agreements in April 2014, resulting in a summer peak demand reduction of approximately 325 MW after April 30, 2019. To supplement the companies’ generating capacity through April 2019, the companies entered into a capacity purchase and tolling agreement with Bluegrass Generation for 165 MW of capacity from May 2015 through April 2019.

The companies are also constructing a 10-MW photovoltaic solar facility at the E. W. Brown station, which is expected to be commissioned in May 2016.

A gas-fired addition looks possible after 2018

The companies have a long-term need for capacity beginning in 2029 in the Base load scenario considered in the IRP, and 2021 in the High load scenario. In five of six Base and High load scenarios, this need was met with natural gas combined cycle (NGCC) capacity; in one scenario, this need was met with simple cycle combustion turbine (SCCT) capacity. In the Low load scenario, the companies do not have a long-term need for capacity in the study period. Based on these results, a natural gas unit will likely be included in the companies’ least cost plan to reliably meet load requirements beyond 2018.

The NGCC technology options have higher capital and fixed operating and maintenance (O&M) costs, but much better heat rates than SCCTs. The “SCCT F-Class-Three Units” option takes advantage of economies of scale, which results in lower capital costs on a dollar per kilowatt ($/kW) basis. Wind and solar options have much higher capital costs than other options on a $/kW basis, but no energy costs.

In the “No ITC or RECs” iteration, the “2×1 NGCC G/H-Class” option was least-cost in 212 of the 270 cases and ranked among the top four least-cost options in all 270 cases. The option to install three F-Class Simple-Cycle Combustion Turbines (“SCCT F-Class -Three Units”) was least-cost in 58 cases. The “2×1 NGCC G/H-Class” option was the best option for meeting intermediate and base load energy needs. The “SCCT F-Class – Three Units” option was the best option for meeting peak energy needs. In the “10% ITC and RECs” iteration, the solar PV and wind technology options were ranked among the top four least-cost technology options in multiple cases.

“ITC” stands for the federal investment tax credit program, which supports renewable technology development. “REC” refers to renewable energy credits. Given the uncertainty in REC prices and the availability of investment tax credits for renewable technologies, two iterations of 270 cases were evaluated:

  • No lTC or RECs: This iteration did not include an ITC for renewable technologies or wind and solar RECs.
  • 10% ITC and RECs: This iteration incorporated a 10% ITC and REC market prices for solar and wind technologies.
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.