Idaho Power identifies issues with further wind additions

Idaho Power has added a lot of wind-generated capacity on its system in recent years, but faces serious issues going forward with squeezing more such capacity on the existing system while at the same time having enough back-up generation to balance wind’s notorious variability.

“As a variable and uncertain generating resource, wind generators require Idaho Power to modify power system operations to successfully integrate such projects without impacting system reliability,” said a wind integration study that the utility released in February in conjunction with an update of its 2011 integrated resource plan. “The company must build into its generation scheduling extra operating reserves designed to allow dispatchable generators to respond to wind’s variability and uncertainty.”

Idaho Power, similar to much of the Pacific Northwest, has experienced rapid growth in wind generation over recent years. As of January 2013, Idaho Power has reached on-line wind generation totaling 678 MW of nameplate capacity.

“This rapid growth has led to the recognition that Idaho Power’s finite capability for integrating wind is nearing depletion,” the study said. “Even at the current level of wind penetration, dispatchable thermal and hydro generators are not always capable of providing the balancing reserves necessary to integrate wind. This situation is expected to worsen as wind penetration levels increase.”

The investigation in the study quantified wind integration costs for wind installed capacities of 800 MW, 1,000 MW, and 1,200 MW. Synthetic wind generation data and corresponding day-ahead wind generation forecasts at these build-outs were provided by Energy Exemplar (formerly PLEXOS Solutions) and 3TIER.

The study employed the following two-scenario design:

  • Base scenario for which the system was not burdened with the incremental balancing reserves necessary for integrating wind; and
  • Test scenario for which the system was burdened with the incremental balancing reserves necessary for integrating wind.

System simulations for the two scenarios were identical, except that generation scheduling for the test scenario included the condition that dispatchable thermal and hydro generators must provide the appropriate amount of incremental balancing reserves. System simulations were conducted for a 2017 test year. Customer demand for 2017, as projected for the 2011 IRP, was used in system modeling. To investigate the effect of water conditions on wind integration, the study also considered Snake River Basin stream flows for three separate historic years representing low (2004), average (2009), and high (2006) water years.

“The study results indicate customer demand is a strong determinant of Idaho Power’s ability to integrate wind,” the study said. “During low demand periods, the system of dispatchable resources often cannot provide the incremental balancing reserves paramount to successful wind integration without creating an imbalance between generation and demand. Under these circumstances, curtailment of wind generation is often necessary to maintain balance. Modeling demonstrates that the frequency of curtailment is expected to accelerate greatly beyond the 800 MW installed capacity level. While the maximum penetration level cannot be precisely identified, study results indicate wind development beyond 800 MW is subject to considerable curtailment risk. Importantly, curtailed wind generation was removed from the production cost analysis for the wind study modeling, and consequently had no effect on integration cost calculations. The curtailed wind generation simply could not be integrated, and the cost-causing modifications to system operations designed to allow its integration were assumed to not be made.”

Integration costs jump sharply beyond 800 MW

In order to fully cover the $8.06/MWh integration costs associated with 800 MW of installed wind capacity, wind generators in the increment between the current penetration level (678 MW) and the 800 MW penetration level will need greater assessed integration costs, the study said. Analysis indicates that these generators will need to recognize integration costs of $16.70/MWh to allow full recovery of integration costs associated with 800 MW of installed wind capacity. Similarly, generators between the 800 MW and 1,000 MW penetration levels introduce incremental system operating costs requiring the assessment of integration costs of $33.42/MWh, and generators between 1,000 MW and 1,200 MW require incremental integration costs of $49.46/MWh.

The addition of 200 MW of installed wind capacity between the 800 MW level and the 1,000 MW level, is projected to result in about 7,600 MWh of curtailment on top of prior curtailments around the 800 MW level. Increasing the installed wind capacity 200 MW further to 1,200 MW is projected to result in another 38,000 MWh of curtailment. “It is important to note the effect of a procedure for curtailment,” the study said. “Spreading the curtailed MWh over the full installed wind capacity of 1,200 MW results in a projected curtailment of about 1.5 percent of produced wind energy. However, if wind generators comprising the expansion from 1,000 MW to 1,200 MW are required under an established policy to shoulder the curtailment burden arising from their addition to the system, curtailment of their energy production is projected to reach nearly 8.5 percent.”

Averaged over the three water conditions considered, the estimated integration costs are $8.06/MWh at 800 MW of installed wind, $13.06/MWh at 1,000 MW of installed wind, and $19.01/MWh at 1,200 MW of installed wind.

Idaho Power first reported on wind integration in 2007. While there was a sizable amount of wind generation under contract in 2007, the amount of wind actually connected to the Idaho Power system at the time of the first study report was just under 20 MW nameplate.

Coal acts as back-up for wind variability, so does gas

Idaho Power, a unit of IDACORP (NYSE: IDA), serves about 500,000 customers in southern Idaho and eastern Oregon. Idaho Power relies heavily on generation from 17 hydroelectric plants on the Snake River and its tributaries. Idaho Power also shares joint ownership of three coal-fired plants (Jim Bridger in Wyoming, North Valmy in Nevada and Boardman in Oregon) and is the sole owner of three natural gas-fired plants, including the new Langley Gulch plant.

“Coal is one of the thermal resources Idaho Power uses to integrate wind generation,” the study pointed out. “Unlike hydro, the fuel for the coal plants comes at a cost. These fuel costs, as well as the lost opportunities created by using the coal capacity to integrate wind, make up another part of the wind integration costs. The coal generators do not have the large range and rapid response provided by the hydro units.”

The study added: “While the operation of baseload coal-fired power plants is expected to decline as a consequence of adding wind to a power system, this decline is offset by a marked increase in generation from gas-fired plants. The rapidly dispatched capacity from the gas-fired plants is widely recognized as critical to the successful integration of variable generation. Wind study modeling suggests that the need to dispatch gas-fired generators for balancing reserves is likely to displace the economic operation of coal-fired generators, particularly during times of acute transmission congestion.”

Idaho Power said it is still grappling with how to deal with the wind integration problem. One area that has been studied in recent years is a Western Electricity Coordinating Council (WECC) field trial of reliability-based control (RBC). The essential effect of RBC on operations is that a balancing authority is permitted to carry an imbalance between generation and demand if the imbalance helps achieve wider system stability across the aggregated balancing area of the participating entities. In effect, the balancing authority area is expanded, and the diversity of the expanded area allows an aggregate balance to be more readily maintained.

“Idaho Power has participated in the RBC field trial since the program’s inception, and has recognized a resulting decrease in the amount of cycling required of generating units for balancing purposes,” the study noted. “However, the effect of RBC was not included in the modeling for this study. This omission is in part related to the status of the program as a field trial, and related uncertainty regarding the structure of RBC in the future, or whether RBC will exist at all. Moreover, while RBC may allow balancing reserves-carrying generators to not respond to changes in load or wind in real-time operations, the scheduling of these generators must still include appropriate amounts of balancing reserves because it is not known at the time of scheduling to what extent an imbalance between generation and load will be permitted.”

Utility gets power under a handful of PPAs

In addition to power purchases in the wholesale market, Idaho Power purchases power under long-term power purchase agreements (PPA). The company has the following notable firm wholesale PPAs and energy exchange agreements:

  • Raft River Energy I LLC—For up to 13 MW (nameplate) from its Raft River Geothermal Power Plant Unit #1 located in southern Idaho. The contract term is through April 2033.
  • Telocaset Wind Power Partners LLC—For 101 MW (nameplate) from the Elkhorn Valley wind project located in eastern Oregon. The contract term is through 2027.
  • USG Oregon LLC—For 22 MW (estimated average annual output) from the Neal Hot Springs geothermal plant located near Vale, Ore. The contract term is through 2037 with an option to extend.
  • Clatskanie People’s Utility District—For the exchange of up to 18 MW of energy from the Arrowrock project in southern Idaho for energy from Idaho Power’s system or power purchased at the Mid-Columbia trading hub. The initial term of the agreement is Jan. 1, 2010, through Dec. 31, 2015. Idaho Power has the right to renew the agreement for two additional five-year terms. 
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.