Updated Appalachian Power plan relies more on renewables

The Appalachian Power (APCo) unit of American Electric Power (NYSE: AEP) on March 11 filed an updated integrated resource plan (IRP) with the Virginia State Corporation Commission that takes into account a lack of 50% of the Mitchell coal plant in West Virginia.

In July 2013, the Virginia commission approved APCo to buy part of the Amos coal plant in West Virginia from an AEP affiliate, but refused to approve its planned buy of 50% (about 780 MW) of the Mitchell plant, saying this was too much of a commitment to coal. The West Virginia Public Service Commission, faced with the Virginia action, in December 2013 approved the Amos buy but deferred a decision on the Mitchell share.

In October 2013, the Virginia commission issued an order in APCo’s 2013 IRP case requiring the March 11 update to be filed. This updated 2014 IRP, among other things, reflects certain generating plant retirements during the 15-year planning period, as a result of environmental requirements. By mid-2015, APCo expects to retire 1,245 MW of older, sub-critical coal-fired plants. In addition, the updated 2014 IRP reflects the conversion of APCo’s Clinch River Units 1 and 2 in Virginia, which currently are coal-fired and would otherwise need to be retired by mid-2015, to natural gas in late 2015 and early 2016, respectively. This has the effect of preserving roughly 480 MW of APCo’s existing generation through about 2025. The Clinch River conversion has been approved by the commissions in both states.

Compared to the company’s August 2013 IRP, which had different assumptions resulting in a different resource mix, this updated plan does not include a merger with fellow AEP subsidiary Wheeling Power or the transfer of a 50% share of the Mitchell station. It does include lower variable cost, intermittent resources in the form of wind, additional utility owned solar and distributed solar.

While the Amos Unit 3 capacity transfer and Clinch River conversion will meet APCo’s shorter-term capacity needs, the consideration of “non-traditional” resources, in the form of additional demand-side management (DSM)/energy efficiency, as well as distributed solar generation and utility-scale renewables (wind and solar) could both:

  • “back-fill” some of the identified energy position shortfall; and
  • possibly allow APCo to defer more “traditional” fossil-based generation capacity additions through the planning period and beyond; particularly commensurate with the assumed (gas-converted) Clinch River retirements next decade.

The Preferred Plan in the 2014 IRP update would reasonably reduce APCo’s reliance on coal-based generation as part of its portfolio of resources, thereby enhancing asset diversity, the utility noted. Specifically, even after retiring 1,245 MW of coal generation in 2015, the company’s capacity mix attributable to coal-fired assets would further decline from 70% to 62% over the remainder of the planning period. Similarly, APCo’s energy mix attributable to coal-based generation would comparably decrease from 80% to 71% over the period.

The planned coal retirements in 2015 are:

  • Clinch River Unit 3 (230 MW), Virginia;
  • Glen Lyn Unit 5 (90 MW) and Unit 6 (235 MW), Virginia;
  • Kanawha River Units 1 and 2 (400 MW), West Virginia; and
  • Sporn Units 1 and 3 (290 MW), West Virginia.

Renewables, energy efficiency a major part of revised plan

This Preferred Plan ramps up energy efficiency to 4.3% by 2028 or approximately 7.8% of the energy requirements associated with the eligible customer base. Renewable resources constitute 12.7% of the energy requirements by 2028.

This plan depends heavily on the assumption of declining or flat costs for renewable resources. Further, as a practical consideration, Utility Solar was limited to approximately 50 MW (nameplate) of solar additions per year as costs to install are anticipated to “bottom-out” at approximately $1.50 per watt. Although utility ownership would certainly be an option, wind resources were effectively modeled as power purchase agreements (PPAs) with declining nominal costs beginning at $65/MWh so as to reflect continued increased efficiency of the wind turbines. Moreover, this approximated wind cost is reflective of the assumed cessation of Federal Production Tax Credits (PTC) over the planning period. Similar to solar resources, the implementation of wind resources was limited to a practically achievable 100 MW each year under a declining cost assumption.

APCo also considered a plan that relies primarily on fossil generation resource additions to meet its future load obligations. This modeled plan exclusively considered more traditional “supply-side” sources, including natural gas combined-cycle (NGCC) and natural gas combustion turbine (NGCT) (i .e . peaking) resources. This “supply-side” view added additional NGCTs (as compared to the Preferred Plan) at various points over the long-term study period beginning in 2026, which is the expected retirement year of the gas-converted Clinch River units.

The Preferred Plan adds only 157 MW of nameplate natural gas generation (starting in 2026) compared to 628 MW in the Supply-side Only Plan. Continuous, smaller additions of renewable and efficiency resources may be preferable to consumers as the impacts on rates would tend to be incremental and steady, the company noted.

Solar power becomes economical in 2019 and beyond, and it is at this point that APCo anticipates beginning to add solar resources. Similarly, (distributed) consumers will benefit under a net metering compensation program as soon as 2016. Recognizing that distributed solar will be begin to be deemed economic by some customers, the Preferred Plan includes distributed solar resources beginning in 2016.

Half share of Mitchell coal plant still out there as a potential issue

The fact that APCo did not consider the potential merger with Wheeling Power in this updated IRP is a critical one. Wheeling Power, right now, is basically a wires company with no generating assets. But, on March 4, APCo and Wheeling Power (WPCo) applied at the West Virginia PSC for approval to transfer that half share of the Mitchell coal plant, the one that the Virginia commission rejected for APCo, to WPCo. That means that if the merger of those two utilities does eventually happen, then the half share of Mitchell would become part of the generating mix for the combined APCo/WPCo.

WPCo’s load is currently served by a contract with the unregulated AEP Generation Resources. The WPCo contract will terminate if some alternate supply mechanism for WPCo is implemented. Mitchell is a 1,560-MW plant located near Moundsville, W.Va., with WPCo now proposed to get half (780 MW) of that capacity. The other half of Mitchell was recently transferred to AEP’s Kentucky Power subsidiary.

Protection from power market volatility will become increasingly important, given the planned retirement of significant amounts of APCo and other coal-fired generating capacity in 2015, much of it as a result of the federal Mercury and Air Toxics Standards (MATS), on top of significant retirements over the past few years, the March 4 application in West Virginia noted. The Mitchell transfer is far superior to other options that might be contemplated, such as constructing new generating capacity, acquiring existing generating capacity, or procuring long-term contracts for power, the utilities said.

On the delicate point that the Virginia State Corporation Commission (VSCC) will eventually need to decide on a merger of APCo and WPCo, and that in the meantime the Mitchell half that the Virginia commission rejected for APCo would have been transferred to WPCo, the March 4 filing said: “At the very least, APCo concludes that it would need to present to the VSCC the changed circumstances involved in the Merger once WPCo’s power supply plan has been determined. Accordingly, the Companies suggest that the Merger will need to await final regulatory approval by all the relevant regulatory bodies after the approval of a power supply plan for WPCo, before it can be consummated. Deferring the Merger will not have an adverse effect on the Companies’ West Virginia customers. Rather, it will provide those customers with significant advantages, by allowing them to receive the benefits of the Mitchell Asset at the earliest possible date, and irrespective of the ultimate outcome of other regulatory proceedings respecting the Merger.”

The AEP companies seem to be saying that as far as the Virginia commission’s reaction to having the half share of Mitchell under WPCo at the time the commission presumptively considers the merger of the two utilities, the companies will cross that bridge when they come to it.

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.