A New Way of Buying Power
November 17th, 2011 by Pam Blair

A multitiered rate structure changes the relationship between public utilities and the region’s primary power supplier

Boaters enjoy a sunny day downstream from the 717-foot Dworshak Dam on the north fork of the Clearwater River in Northern Idaho. Photo by Mike Teegarden

Boaters enjoy a sunny day downstream from the 717-foot Dworshak Dam on the north fork of the Clearwater River in Northern Idaho. Photo by Mike Teegarden

Buying power from the Bonneville Power Administration will get more complicated for your electric utility on October 1, when BPA’s new rate design kicks in. It also will get more expensive.

Costs are going up to pay for operations and maintenance. BPA’s new rate design also will differentiate between power generated from the federal system and supplemental purchases.

Electricity from the network of hydropower facilities along the Columbia and Snake rivers—and the nuclear Columbia Generating Station—will be sold at cost in what is called Tier 1 rates.

Each utility has been granted a share of Tier 1 power. If that is insufficient to meet the utility’s needs now or in the future, the utility can pay BPA the market price to fill that gap at Tier 2 rates, buy from someone else or generate its own power.

In November 2009, BPA’s 135 public utility customers had to specify how they would handle loads beyond their Tier 1 shares for a three-year period beginning in October. By September 30, 2011, they must commit for the 2015 to 2019 period.

If the uncertainty of forecasting power needs so far out isn’t enough of a challenge, consider that Tier 1 rates have three components, each of which will be itemized on the utilities’ wholesale power bills:

  • Customer charge. A fixed monthly fee charged to each utility to cover BPA’s cost of running the federal system.
  • Load shaping charge. A credit or charge based on whether the utility’s load comes at a time when the federal system has plenty of power or when BPA must buy power to meet load requirements.
  • Demand charge. A charge assessed to reflect the utility’s peak usage.

“Bills will be more complicated,” says Geoff Carr, assistant director of Northwest Requirements Utilities (NRU). “We have not made life simpler.”

Assessing What the Rate Change Means
Utilities are analyzing how the new rate structure will affect them, and working on strategies to deal with it. The urgency varies depending on whether the utility is slow or fast growing.

Hood River Electric Cooperative, based in Odell, Oregon, expects to benefit from the new way BPA will bill utilities.

“With the new Tier 2 structure you can be either a winner or a loser, depending on the timing of the loads,” says Manager John Gerstenberger. “We had greater swings under the current rate structure. It flattens ours out. We are not a fast grower.”

Jake Eimers, manager of Idaho County Light and Power, based in Grangeville, expects little growth in the near future.

“I am hoping that we have a year or two to see what the impact is going to be and see what other utilities are doing,” he says.

Steve Eldrige, general manager and CEO of Umatilla Electric Cooperative, based in Hermiston, Oregon, cannot wait to see. Two large data server farms begin operations in his area this year.

“Our role is not to stand in the way of development by making new members pay based solely on new power supply costs,” Eldrige says, noting that would be the result if UEC had them bear the entire burden of Tier 2 rates. “We also do not want one group of members subsidizing another.”

That would be the case if Tier 1 and Tier 2 rates were simply rolled together.

With input from member groups, UEC is developing its own tiered rate system. Existing customers or new customers with growth of more than half an average megawatt per year, as calculated on a rolling three-year average base usage, also will fall under Tier 2 rates.

The new BPA rate structure means utilities must think differently, Carr says.

“How do you deal with new industrial customers coming to town?” he asks. “How do you inspire customers to reduce demand at peak times? If you are a winter peaking utility, how do you shift that?”

Strategic Partnerships are Important
Twenty of NRU’s 50 customers joined power purchasing groups created by the organization to work on serving loads beyond Tier 1 allotments.

Sixteen Northwest co-ops are part of PNGC Power—a joint operating entity that acquires, pools and supplies power.

“We have an ability to manage risk in a number of ways,” says Doug Brawley, senior vice president of BPA supply and member rates. “That includes helping with demand-side management, conservation programs and developing resources as a group.”

Carr says resource development in the region is critical.

“We are only renters of Bonneville Power,” he says. “We pay off the investment, and still we are paying the bill. What do we have to show for it? We really need to think about resources.”

What You Can Do
Because your utility will be billed for both the power used and the time of day it is used, you can help reduce the financial impact on your utility—and your electric bill—in two ways:

  • Use electricity more efficiently.If your utility is able to stretch its allotment of Tier 1 power, it will be less susceptible to the higher-cost Tier 2 power or its alternatives. That means you will pay less.
  • Shift electricity use. If the peaks and valleys of electricity use can be leveled out, your utility will save money. That could be achieved by such things as doing laundry and running the dishwasher at nonpeak times.