Solar generation and transmission capacity are the initial additional resources identified for offsetting early coal capacity retirements in the preferred portfolio of Idaho Power’s 20-year 2019 integrated resource plan.

The portfolio calls for 220 MW of solar in the early 2020s, along with up to 500 MW of transmission capacity by 2026 from the proposed Boardman to Hemingway (B2H) line.

Natural gas, however, is by far the largest new resource included in the portfolio. It calls for adding 800 MW of natural gas starting in 2028 to make up for 1,028.5 MW of coal-power generation slated for retirement.

Three-fourths of the natural gas capacity would be added in 2035 and later. However, that would be too late to depreciate those resources by Idaho Power’s pledge to rely on 100 percent carbon-free energy by 2045.

Nonetheless, the company remains committed to achieving that goal, Idaho Power spokesman Brad Bowlin said. “Obviously between now and [when the plan calls for additional natural gas resources], we’ll be looking at alternatives to those gas plants.”

However, in the utility’s earnings call in May, Mitch Colburn, Idaho Power’s resource planning and operations director, said that natural gas—along with solar and storage—would be considered in the future.

Following the call, utility spokesman Jordan ­Rodriguez told Clearing Up, “While the company is committed to its 100 percent clean energy goal, we also remain mindful of cost and reliability. Given that the IRP is a 20-year outlook, natural gas may continue to be ­identified as an option in the near-term future.”

The company expects “improvements in technology will allow us to move toward additional clean energy, and we will continue to look at all options while balancing reliability, environmental responsibility, efficiency, risk and cost as we work on the IRP,” Rodriguez said.

The new IRP is a marked change from the utility’s previous plan, which did not include solar resources in its preferred portfolio—although it did include “­consideration” of solar in its action plan.

In addition, coal retirements are moved forward in the 2019 IRP. The plan recommends earlier retirements for two of the four units at the Jim Bridger coal-fired plant in Wyoming. Idaho Power owns 770.5 MW, or one-third, of the plant, and PacifiCorp owns the rest and operates the facility.

The 2019 IRP recommends s­hifting Unit 1’s retirement date from 2028 to 2022 and Unit 2 from 2032 to 2026. It also recommends retiring the last two units in 2032, which was not c­ontemplated in Idaho Power’s 2017 IRP (CU No. 1808 [10]).

The plan also confirms the ­company’s decision to move forward with its exit from the North Valmy coal-fired plant in Nevada that it co-owns with Nevada Energy (CU No. 1895 [14]), leaving Unit 1 later this year and Unit 2 in 2025.

Idaho Power has asked the Idaho PUC to approve its exit from Unit 1 [IPC-E-19-08], but has not yet filed that request with Oregon regulators.

The loss of North Valmy’s capacity—each unit is 127 MW—can be made up for with imports over the 345 kV transmission line connecting the plant to Idaho Power’s grid, according to the plan.

Idaho Power has 100 percent of the northbound capacity, which currently is fully subscribed to the North Valmy plant’s output. Planned upgrades to the line in 2020 will increase capacity from 262 MW to 360 MW.

The plan cautions that “the depth of the market and associated availability of resources is not as certain for the Idaho-Nevada path as it is for the Idaho-Northwest path during summer peak hours, so import availability will continue to be evaluated in the future.”

The IRP charts a path to a cleaner future, which the utility announced in March (CU No. 1895 [9]).

“This plan shows the way forward as we work toward our goal of providing 100 percent clean energy by 2045,” Idaho Power’s Vice President of Power Supply Tess Park said in a news release. “We see less coal, more solar and increased transmission capacity from the Northwest, while hydropower remains the backbone of our system.”

The preferred portfolio includes the addition of 120 MW of solar generation in 2022 and another 100 MW the following year. Both additions would come from Jackpot Solar, a development planned by ­Franklin Solar. In April, Idaho Power filed with the Idaho PUC for approval of a power purchase agreement with the developer, which plans to build the facility in two stages [IPC-E-19-14]. The agreement gives the utility the option of acquiring the resources when they come on line in 2022 and 2023 (CU No. 1899 [14]).

The 300-mile, 500 kV Boardman to Hemingway transmission line is slated to come on line in 2026. Idaho Power expects 500 MW of west-to-east transfer capacity in April through September, which ­coincides with the utility’s summer-peaking demand curve, and 200 MW during the other months. The additional ­transmission capacity is key to offsetting earlier coal exits, according to Idaho Power. The company is ­partnering with BPA and PacifiCorp to construct the line.

However, the project still must clear several ­regulatory and permitting decisions. So far, a vocal and dedicated grassroots opposition has not convinced regulators or permitting authorities to put the brakes on the proposed development. Twelve of the 24 portfolios in the 2019 IRP do not include adding B2H.

There is little difference in cost between the portfolios that include B2H and those that omit it, said Jim Kreider, an organizer of STOP B2H, which is leading the charge to thwart construction of the line.

Including the line’s indirect costs—such as environmental damage and lost revenue from farming, grazing and timber—would make a portfolio that excludes B2H the preferred option, he said.

The non-B2H portfolios are most attractive under scenarios with high carbon and natural gas prices. Under those conditions, not building B2H would be the least-cost option.

The 2019 IRP includes several notable ­methodological changes. Most significant, the company used ­AURORA’s long-term capacity expansion model to construct the plan’s 24 portfolios. In previous plans, it took a more manual and qualitative approach. The change is in response to feedback from the prior IRP approval ­process and the company’s public advisory committee, said Kresta Davis-Butts, Idaho Power’s senior manager of resource planning and operations hydrology.

“One of the things we saw [with the different approach] is a diversity in portfolios” envisioning different futures for the company, Davis-Butts told Clearing Up.

Those differences, though, are most apparent further out into the future. Many of the portfolios envision similar action plans in the first four to five years, which gives the company more confidence in its plans for the near future, she said.

While the utility used a different modeling ­methodology, it was not a radical change and it did not significantly alter its variable forecasting methodologies.

“I don’t think there are really big swings in our assumptions,” Davis-Butts said. “But [the model’s more optimal approach] allowed us to put those assumptions in play” to a greater degree.

The 2019 IRP used an adjusted Platts 2018 Henry Hub natural gas price forecast and included variations to that forecast using the 2018 Energy Information Administration reference case and the 2018 EIA low oil and gas case.

It also included four carbon prices, none of which ­envisioned a state program. The Planning Case Carbon Cost is based on a Wood Mackenzie report released in 2018 and includes a $2 per ton cost beginning in 2028, increasing to $26/ton by the end of the IRP’s 20-year projection.

Idaho Power also changed its demand planning ­benchmarks from its 2017 IRP, which used 95th ­percentile peak-hour capacity. This time, the IRP used the 50th ­percentile peak-hour forecast with a 15 percent ­planning margin. The company compared its results with its p­revious benchmark and found little difference. Furthermore, the change is more aligned to the benchmarks used by other Northwest IOUs in their most recent approved IRPs.

The preferred portfolio includes 50 MW of demand response, to be added starting in 2026, based on its ­attributes and costs rather than specific features.

“Before, we would just bake DR in,” Davis-Butts said.

The preferred portfolio also included 440 MW of peak summer capacity reduction from existing and future demand response resources and 234 aMW of average annual load reduction from energy efficiency. Energy efficiency is also expected to reduce peak demand by 367 MW.

The least-cost option includes 60 MW of battery ­storage, to be added toward the end of the planning period. The model only considered its value in terms of energy, and didn’t include ancillary benefits that ­proponents of the technology say are key to truly valuing the full benefit of adding storage capacity.

Idaho Power was unable to make progress on ­incorporating those other benefits in this IRP, Davis-Butts said. “We know that is something that we need to work on outside” the IRP process.

“It is something we need to have better ­understanding on,” before it can be put into the model, she said.