Appalachian Power to continue to rely on last two coal-fired plants

The latest Integrated Resource Plan (IRP) from Appalachian Power (APCo), filed on Dec. 30 at the West Virginia Public Service Commission, sees a long-term future with less coal-fired generation.

Appalachian Power is a unit of American Electric Power (NYSE: AEP) that has a service territory stretching from southern West Virginia into southwest Virginia.

The utility noted that this plan is not a commitment to specific resource additions or other courses of action, since the future is highly uncertain, particularly in light of current economic conditions, the movement towards increasing use of renewable generation and end-use efficiency, as well as current and future environmental regulations, including the EPA’s recently-final Clean Power Plan, which calls for 32% greenhouse gas reductions from existing power plants by 2030.

Also, APCo faced a number of other dynamic circumstances as it developed the assumptions and analyses outlined in this IRP. For example, on June 9, 2015, the Federal Energy Regulatory Commission (FERC) issued an order pertaining to PJM Interconnection’s recently proposed Capacity Performance construct, thereby providing guidance to PJM on its capacity market proposals. While the company incorporated its expectations regarding Capacity Performance into this report, APCo is still evaluating the FERC order, the full impact of which will not be known until tariffs are accepted by the FERC.

The company noted that its next IRP, which is to be filed on on May 1, 2016, at the Virginia State Corporation Commission, is likely to reflect updated assumptions, analyses, and results. APCo is required to provide an IRP that encompasses a 10-year forecast period (in this filing, 2016-2025). Although only a ten year period is required to be reported, APCo’s modeling efforts encompass a 30 year analysis period in order to determine the long term impact of changes to APCo’s portfolio.

From a capacity viewpoint, the 2020/2021 planning year is when PJM’s new Capacity Performance rule will take full effect, potentially limiting the capacity value of intermittent resources, such as run-of-river hydro, wind, solar, as well as pumped storage hydro, thereby creating a greater future need within APCo for additional capacity. Keeping these considerations in mind, APCo has developed an IRP that provides adequate supply and demand resources to meet peak load obligations for the next ten years. The key components of this plan are for APCo to:

  • finish the conversion of Clinch River Units 1 and 2 in Virginia from coal to natural gas;
  • proceed with the decommissioning and retirement of Kanawha River Units 1 and 2 in lieu of converting those coal units to natural gas;
  • diversify its mix of supply-side resources through the addition of cost-effective wind, large-scale solar, and natural gas-fired generation resources, as necessary;
  • implement demand-side resources in the form of additional energy efficiency programs and Volt VAR Optimization (VVO) installations; and
  • recognize that residential and commercial customers will add distributed resources, primarily in the form of residential and commercial rooftop solar.

The IRP development process considered regulation of greenhouse gas (GHG) emissions. For that purpose, a reasonable proxy was utilized in the IRP that assumed that the resulting economic impact would be equivalent to a “tax” applicable to each ton of carbon dioxide (CO2) emitted from fossil-fired generation sources which would take effect beginning in 2022. Under the company’s most-expected, or “Base” pricing scenario, the cost of such CO2 emissions is expected to stay within the $15-$20/metric ton (tonne) range over the long-term (30-year) analysis period.

On Oct. 23, 2015, the EPA published the final Clean Power Plan, which establishes CO2 emission guidelines for existing fossil generation sources under Section 111(d) of the Clean Air Act. APCo is currently in the process of reviewing this plan. APCo, its parent company American Electric Power, and other stakeholders will be working in the coming months and years to better understand the requirements of the final CPP, to work with state agencies – including the West Virginia Department of Environmental Protection (WVDEP) – to develop reasonable compliance plans, and then to develop strategies for compliance with those final approved plans.

APCo’s total internal energy requirements are forecasted to increase at a compound average growth rate (CAGR) of 0.3% through 2025. APCo’s peak internal demand is forecasted to increase at a CAGR of 0.2%, with annual peak demand expected to continue to occur in the winter season through 2024. Through 2020, APCo has resources to meet its forecasted internal demand; however, in 2021 APCo is anticipated to experience a capacity shortfall based upon APCo’s assumptions regarding the timing and parameters of PJM’s Capacity Performance rule.

The modeling process included numerous sensitivity analyses unique to APCo in order to understand the impact of specific changes to APCo’s portfolio. These sensitivities included converting the Kanawha River Plant to natural-gas, the retirement of a large coal-fired unit, and the substitution of a natural gas combined-cycle plant in place of a future natural gas combustion turbine plant.

Hybrid Plan offered as the best compromise

APCo used the results of the modeling to develop a “Hybrid Plan.” The Hybrid Plan is presented as an option that attempts to balance cost and other factors while meeting APCo’s peak load obligations. In addition, this IRP considers environmental constraints and the viability of customer self-generation. In summary, the Hybrid Plan:

Addresses expected PJM Capacity Performance rule impacts on APCo’s capacity position beginning with the 2020/2021 PJM planning year. Among other things, it assumes that the rule may result in APCo:

  • Reducing the level of Smith Mountain pumped storage firm capacity contribution by approximately 200 MW (from 585 MW to 385 MW).
  • Reducing wind resources from prior PJM-recognized capacity levels (from 13% to 5% nameplate capacity).
  • Reducing run-of-river hydro contributions such that they would no longer provide firm capacity.
  • Maintaining solar resources at previous PJM-recognized levels of 38% of nameplate capacity.

Adds 10 MW of large-scale solar energy by 2018, with subsequent additions throughout the planning period; for a total of 260 MW (nameplate) by 2025.

Adds 150 MW wind energy by 2018, followed by 150 MW additions in 2020, 2021, 2022, and 2025; for a total of 750 MW (nameplate) of wind over the 10-year planning period.

Implements customer and grid energy efficiency, including VVO programs, reducing energy requirements by 1,129 GWh (or 3.1% of projected energy needs) and capacity requirements by 118 MW by 2025.

Assumes APCo’s customers add distributed solar capacity, increasing by 5% annually, and totaling over 14 MW (nameplate) by 2025.

Adds 10 MW (nameplate) of battery storage resources in 2025.

Continues operation of APCo’s facilities including the Amos Units 1-3 and Mountaineer Unit 1 coal-fired facilities, the Ceredo and Dresden natural gas facilities and existing hydro facilities. Maintains APCo’s share of Ohio Valley Electric‘s coal facilities: Clifty Creek Units 1-6 and Kyger Creek Units 1-5.

Retires natural gas-converted Clinch River Units 1 and 2 in 2026.

The Hybrid Plan would reduce APCo’s reliance on coal-based generation and increase reliance on demand-side and renewable resources, improving the diversity of the portfolio. Over the 10-year planning horizon the company’s nameplate capacity mix attributable to coal-fired assets would decline from 60.6% to 52.6%. Renewable assets (wind and solar) climb from 5% to 15.9%, and demand-side resources (including Energy Efficiency, VVO, and Demand Response) increase from 2.9% to 4.1% over the planning period.

APCo’s energy output attributable to coal-fired generation shows a substantial decrease from 85.4% to 71.2% over the period. The Hybrid Plan shows a significant increase in renewable energy (wind and solar), from 3.3% to 12.4%. Energy from these renewable resources, combined with EE and VVO energy savings serve to reduce APCo’s exposure to energy, fuel and potential carbon prices.

Several coal units have been shut, and Kanawha River won’t be revived on gas

One unique resource considered, but not ultimately introduced into the final Hybrid Plan, was the natural gas conversion of the Kanawha River Plant, which ceased operation as a coal-fired facility on June 1, 2015. This supply-side resource was an option in all scenarios analyzed and was the subject of specific sensitivity analyses. Ultimately, the natural gas conversion of the Kanawha River Plant was determined to be uneconomical for APCo.

As of June 1, 2015, the company has made substantial changes to its generation fleet in order to comply with existing and future environmental regulations. The changes include:

Retirement of seven coal-fired units totaling 1,245 MW due to the implementation of the U.S. Environmental Protection Agency’s MATS rule:

  • Clinch River Unit 3 (230 MW) – Carbo, VA
  • Glen Lyn Unit 5 (90 MW) – Glen Lyn, VA
  • Glen Lyn Unit 6 (235MW) – Glen Lyn, VA
  • Kanawha River Unit 1 (200 MW) – Glasgow, WV
  • Kanawha River Unit 2 (200 MW) – Glasgow, WV
  • Sporn Unit 1 (145 MW) – Graham Station, WV
  • Sporn Unit 3 (145 MW) – Graham Station, WV

Refueling of two units from coal to gas (currently underway):

  • Clinch River Unit 1 (237 MW) – Carbo, VA
  • Clinch River Unit 2 (237 MW) – Carbo, VA

As a result of these modifications to APCo’s generating fleet, the remaining wholly-owned coal-fired units in the fleet are the supercritical units at the Mountaineer and Amos plants. 

APCo’s supercritical units (Amos Units 1-3, Mountaineer Unit 1) are able to meet the MATS requirements as a result of previously installed Selective Catalytic Reduction (SCR) for mitigation of NOx emissions and FGD systems for mitigation of SO2 emissions, which together achieve a co-benefit removal of mercury as well. APCo’s sub-critical units which could not meet the MATS requirements in their existing configuration are in the process of being refueled to natural gas-fired units (Clinch River Units 1 & 2) or were retired as of June 1, 2015 (Kanawha River Units 1 & 2, Glen Lyn Units 5 & 6, Clinch River Unit 3 and Sporn Units 1 & 3).

AEP’s Wheeling Power sees future for its 50% share of Mitchell coal plant

AEP’s Wheeling Power (WPCo) subsidiary filed a separate IRP on Dec. 30 at the West Virginia commission. Its generation resources currently consist of a 50% interest in the Mitchell Plant, located in Moundsville, WV. The Mitchell Plant is comprised of two coal-fired, supercritical units, both placed into service in 1971. Unit 1 and Unit 2 are rated at 770 MW and 790 MW, respectively. WPCo’s 50% share is equivalent to 780 MW. AEP’s Kentucky Power unit owns the other 50% of the plant.

The Mitchell Plant is able to meet the MATS requirements as a result of previously-installed SCR for mitigation of NOx emissions and Flue Gas Desulfurization systems for mitigation of SO2 emissions, which together achieve a co-benefit removal of mercury as well.

“This IRP summarizes WPCo’s ability to meet projected demand with its interest in the Mitchell Plant,” said the filing. “Analysis and modeling of additional resources was not conducted due to the Company’s lack of a need for capacity and energy resources.”

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.