Dominion fights it way through last stages of year-long IRP process

The September 2011 integrated resource plan of Virginia Electric and Power, d/b/a Dominion Virginia Power should be found by the Virginia State Corporation Commission as reasonable and criticisms of outside parties should be rejected, the utility said in an Aug. 8 brief.

Consistent with its ruling in the 2009 IRP proceeding, the sole issue for commission consideration is whether the company’s 2011 plan is reasonable and in the public interest, the utility said. DVP is a unit of Dominion Resources (NYSE: D).

“The Plan is supported by well-established industry standard modeling protocols, based on the Company’s assumptions regarding load growth, commodity price projections, demand-side management (‘DSM’) programs, and many other regulatory and market developments expected to occur over the 25-year Study Period (2012 to 2036) at the time the Plan was developed, approximately one year ago,” DVP wrote. “The Company’s overall planning process is a dynamic, ongoing process. To the extent there are changes to the assumptions that form the basis of the Plan since the filing of the Plan, whether due to new or revised regulations or legislation, changes in the load forecast or forecasts of fuel or other commodity prices, the effects of those changes will be incorporated into future integrated resource plans.”

Only some environmental groups, called the “Environmental Respondents,” and the Electric Power Supply Association (EPSA) assert that the 2011 plan should not be approved as being reasonable and in the public interest, the utility wrote, adding that these conclusions are not based on the evidence or established law.

DVP’s long-term load forecast found that over the 15-year Planning Period (2012-2026), the company is expected to have future annual increases in energy requirements of 1.89% and peak demand of 1.93%. One of the main areas of uncertainty in the 2011 plan was assumptions related to new U .S. Environmental Protection Agency regulations concerning air, water and solid waste. The company systematically approached this uncertainty during the 2011 IRP process by examining options for its existing fleet which considered alternatives for the environmentally “at-risk” units to determine the most cost-effective plan.

This analysis determined one of three options for each “at risk” unit: retrofit with additional emissions control equipment; repower with biomass or natural gas; or retire the unit. The resulting retrofits, repowers and retirements are identified in the plan; however, it is important to note that those determinations will evolve over time as environmental regulations progress, the company said.

The company also incorporated planned generation unit uprates, capacity procured pursuant to contracts and its planned generation under construction which included facilities already approved to be built by the commission such as the newly-completed, coal-fired Virginia City Hybrid Energy Center, and those that were pending approval at the time the plan was filed, such as the gas-fired Warren County Power Station.

This process yielded the company’s current capacity and energy positions that by 2026 represent a capacity gap of 8,428 MW and an energy gap of 48,859 gigawatthours absent the addition of new resources. Once the gaps were identified for capacity and energy, the company developed four alternative plans to meet the projected capacity and energy needs that represented plausible future paths. Based on this evaluation, the Base Plan was identified as the “Preferred Plan,” which provided the lowest reasonable cost plan given possible future conditions and other considerations such as fuel diversity and uncertainty surrounding future coal retirements throughout the industry.

Preferred Plan includes actions like coal unit retirements, conversions

The 2011 Preferred Plan contains a balanced mix of resources, including combined-cycle facilities, combustion turbines, nuclear, coal-to-biomass conversions, demand side management (DSM) programs, environmental retrofits, repowers and in some instances, retirements of older coal units, as well as economic market purchases of capacity and energy from PJM.

The company is filling the anticipated capacity gap with a balanced, cost-effective mix of market purchases, new construction and DSM. The Preferred Plan contains a significant amount of baseload renewable generation including 59 MW of renewable capacity based on partial biomass burn at the largely coal-fired Virginia City Hybrid Energy Center, which has achieved commercial operation, and 153 MW of renewable capacity from the conversion of three small coal plants – Hopewell, Southhampton and Altavista – to biomass to be completed by the end of 2013. The plan includes the company’s continued development of DSM programs that are expected to reduce overall peak demand of the company’s system by approximately 940 MW and overall energy consumption.

EPSA says utility is improperly cutting out off-system power buys

“EPSA contends that Dominion’s 2011 IRP, as filed with the Commission, is neither reasonable nor in the public interest because the Company has failed to properly evaluate all available options, including short- and long-term market opportunities, to meet any need for capacity,” said an Aug. 8 EPSA brief. “The record demonstrates that PJM, the regional market of which Dominion is a member, has ample existing capacity to meet any purported need in Virginia through 2016 and has met the capacity needs of its members in every year since its inception. Further, according to the 2011 IRP, Dominion has no intention to enter into any power purchase agreements with independent power producers or to renew any of its existing contracts with non-utility generators physically located in Virginia.”

If the commission does not require an open and transparent competitive market test either in the IRP or a Certificate of Public Convenience and Necessity (CPCN) process, Dominion’s customers could be forced to pay significant costs in excess of what they would otherwise be required to pay for unneeded generation for years to come, said EPSA. Absent a competitive market test to ensure customer needs are met at the lowest reasonable price, the 2011 IRP cannot be considered reasonable and in the public interest, it added.

Virginia Attorney General has questions that need answers

An Aug. 8 brief from the Office of the state Attorney General’s Division of Consumer Counsel was generally supportive of the IRP. But, in answer to the commission’s request at the end of the hearing in this case that the parties provide a list of issues for the commission to address, Consumer Counsel identified the following issues:

  • whether the company’s plan to phase out virtually all third-party power supply as a resource option in favor of company-owned self-build generation is reasonable;
  • whether it was reasonable for Virginia Power to include the construction of a new nuclear unit in each modeled scenario of its plan; and
  • whether the company should consider alternative rate designs, such as a flat or inclining block rate, as a means to achieve the General Assembly’s demand reduction goals.

Also, the Consumer Counsel said it continues to believe that in most circumstances DVP should formally consider and evaluate actual (not simply modeled) potential market alternatives before requesting certification of new generating resources, and that the results of such market evaluations should be provided as evidence to support certificate applications. Finally, Consumer Counsel would recommend that the commission, if it approves the company’s IRP, make clear that such approval does not constitute an endorsement of any individual projects or expenditures contained in the plan.

Enviro groups say company relies too much on gas, not enough on DSM

The environmental groups – Appalachian Voices, Chesapeake Climate Action Network and the Sierra Club – said in their own Aug. 8 brief that all resources were not considered by the utility on a “level playing field.” DSM and renewable energy options were not evaluated fairly as compared to fossil fuel-fired generation units, they said.

The company, for example, selected six natural gas, combustion turbine generation stations (CTs) at 400 MW per plant (200 MW per unit), in 2020, 2021, 2023, 2024, 2025 and 2026, the group noted. The company also includes two combined cycle natural gas plants (CCs) in 2016 and 2019. “With the exception of the 2016 CC, these natural gas plants appear in the Preferred Plan, despite the fact that their locations have not been selected, pipeline capacity has not been confirmed, and costs have not been delineated,” the groups wrote. “That is, these CTs and CCs are simply ‘generic’ plants used as placeholders in the IRP. The Company, however, did not evaluate a ‘generic’ 400-megawatt DSM portfolio. The only new DSM resources considered were programs that had already been developed for filing with the Commission. Additional future DSM resources were not modeled at all from 2014-2026, and DSM growth levels off after the first half of the planning period, in part due to low market saturation assumptions.”

With regard to the company’s Renewable Plan (Alternative Plan D), Dominion considered meeting 20% of its energy needs by 2020 through a massive renewable bundle of offshore wind, onshore wind, and distributed solar generation, the groups added. It did not, however, consider small blocks of renewable energy in the Renewable Plan, they said. Dominion also did not consider each of the renewable resources separately from the bundle, and did not evaluate renewable resources being developed on a different timeframe, from 2021 to 2026. “Instead, Renewable Plan D effectively set up a straw man, ‘all-or-nothing’ approach to renewable energy development,” the environmental groups added.

These deficiencies notwithstanding, the 2011 IRP does represent a step forward from the company’s 2009 IRP, the environmental groups conceded. “Most notably, the Company improved its analysis of environmental compliance costs affecting coal,” the groups said. “These costs incorporate adverse public health and environmental impacts attributed to coal-fired generation, which are now being internalized through regulation. Company decisions to retire coal-fired units at Yorktown and Chesapeake and to reject new coal-fired generation as a future resource option can be traced to a more accurate assessment of these public health and environmental compliance costs. Nevertheless, improvements are needed to meet the statutory requirements of ‘reasonable’ and ‘in the public interest.’”

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.