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Courses › Western Grid Projects: CAISO, Markets, SWIP-N and Hemingway

Lesson 4 of 9 · about 18 minutes

How a Transmission Line Gets Into Your Bill

You'll be able to

  • Separate the questions FERC decides about transmission from the ones the Idaho PUC decides
  • Explain why a certificate of public convenience and necessity is not approval to charge customers
  • Compute a first-year revenue requirement for a transmission investment and spread it across customers
  • Describe how the SWIP-N and B2H certificate orders handled cost risk

The power grid course built the basic rate formula in Who Regulates the Grid: revenue requirement equals operating expenses plus depreciation plus taxes plus rate base times rate of return. It also rebuilt a residential bill line by line in How Your Power Bill Is Built. This lesson applies those tools to one kind of cost: big transmission lines. They are the most expensive single assets most utilities build, they last fifty years or more, and they usually serve more than one state. That makes their path to a bill longer than most.

Two regulators, two questions

A 500 kV line carries power across state lines. That puts its wholesale use under federal law. Section 205 of the Federal Power Act requires that rates for interstate transmission be "just and reasonable" and filed with FERC. So FERC decides what a utility may charge other companies to move power over its lines, through the utility's open access transmission tariff, and it approves the agreements that set up jointly owned projects. That is why the CAISO and Great Basin development agreement for SWIP-N went to FERC, which accepted it in January 2025.

The Idaho PUC decides two different things for an Idaho investor-owned utility. First, whether it may build at all: Idaho Code 61-526 says an electrical corporation may not begin construction of a new line without a certificate that "present or future public convenience and necessity require" it. Second, what retail customers pay: Idaho Code 61-502 directs the commission to set "just, reasonable or sufficient rates."

QuestionWho decides for an Idaho investor-owned utility
May the utility build or buy into the line?Idaho PUC, through a certificate (61-526)
Across federal land, may the line use the route?BLM, through a right-of-way grant
On private land, is the use allowed under local zoning?County or city, through permits such as a special use permit
What may others be charged to use the line?FERC, through the transmission tariff
Are the costs prudent, and how much goes into Idaho retail rates?Idaho PUC, in a later rate or recovery case
How are costs split between Idaho and other states the utility serves?Each state commission, applying an allocation method
A certificate answers "may you build?" A rate case answers "what will customers pay?" Residents who wait for the rate case to raise cost concerns have often waited too long to change the project, and residents who stop after the certificate have left the money fight before it starts.

The path of one transmission dollar

  1. Certificate. The utility shows need, usually from its integrated resource plan. The PUC can attach conditions.
  2. Construction. Spending accumulates on the books. Costs are not in rates yet.
  3. In service. The line is energized and becomes "used and useful."
  4. Recovery case. The utility asks to add the investment to rate base. Staff and intervenors test whether each cost was prudent.
  5. Allocation. A multi-state utility splits the cost among its states. Idaho Power serves customers in Idaho and Oregon; PacifiCorp serves six states.
  6. Class split and tariff. A cost-of-service study divides Idaho's share among residential, irrigation, commercial and industrial classes, and the result is written into the tariff.
  7. Credits. Money the utility collects from other companies using its lines under the FERC tariff is typically credited back against what retail customers pay. Look for the transmission revenue credit in any rate case.

The arithmetic of a line

Example: $140 million of new transmission plant

An invented utility, Basin River Electric, puts $140 million of transmission plant into service. Assumptions, all invented but in realistic ranges: a 7.2 percent overall rate of return, 50-year straight-line depreciation, and $3.5 million a year of operations, maintenance and property taxes.

  • Return: $140,000,000 x 0.072 = $10,080,000
  • Depreciation: $140,000,000 / 50 = $2,800,000
  • Operations and taxes: $3,500,000
  • First-year revenue requirement: 10.08 + 2.80 + 3.50 = $16.38 million

Now year 11. Ten years of depreciation have come off: 10 x $2.8 million = $28 million. Rate base is $140 million minus $28 million = $112 million. Return falls to $112,000,000 x 0.072 = $8,064,000. Revenue requirement: 8.064 + 2.80 + 3.50 = about $14.36 million. Customers pay the most in the early years.

Spread it across customers. If 95 percent of the cost is allocated to the home state: $16.38 million x 0.95 = $15.56 million. With 650,000 customers, that averages $15,561,000 / 650,000 = about $23.94 per customer per year. A residential class carrying 45 percent of the cost with 552,500 homes: $15,561,000 x 0.45 / 552,500 = about $12.67 per home per year, or about $1.06 a month.

Then subtract benefits. If the line lets the utility avoid building a $10 million-a-year peaking plant, the net cost is far lower. That avoided-cost comparison is the heart of every transmission certificate case, and the numbers in it deserve the most scrutiny.

A dollar a month sounds small. Stack a dozen projects and a rising return on equity and it is not. And for a large irrigation pumper or a factory, the class share can be many thousands of dollars a year, which is why the Idaho Irrigation Pumpers Association and the Industrial Customers of Idaho Power show up in transmission cases.

How the two big certificate orders handled cost risk

Boardman to Hemingway, Order No. 35838 (June 30, 2023). The commission granted Idaho Power's certificate and set a soft cap: recoverable costs equal to the company's own estimate, with "detailed support and justification" required for anything above it. Staff had asked the commission to require tracking of outside costs if the line slipped past June 1, 2026; the commission did not adopt that as written. Instead it said that if delays require mitigation, the company should compare the line's total cost with and without the delays. It also ordered the company to show its pursuit of other funding sources when it asks for recovery.

SWIP-N, Order No. 36874 (December 12, 2025). Idaho Power did not ask for binding ratemaking treatment, and the commission made no finding on the prudence of any cost. Recovery waits for a future case, where the company must provide final installed costs and documentation for deviations. The order also lists protections in the deal with Great Basin Transmission, including a reduced build-transfer fee if costs run over or the project is late, and no payments until construction is complete.

The other 77 percent of SWIP-N's cost runs on a different track entirely. CAISO funds 77.169 percent of the project in exchange for most of the capacity, and Great Basin must file a transmission owner tariff and revenue requirement at FERC as a CAISO participating transmission owner, according to CAISO's September 2024 board memo. That share is paid through CAISO's transmission rates by users of CAISO's grid, mostly in California, not through Idaho rates.

Two numbers to keep handy. CAISO's high-voltage Transmission Access Charge was about $14.60 per MWh in mid-2025. And FERC's standard incentive for a utility that joins an ISO or RTO is a 50-basis-point boost to its allowed return, under Order No. 679 (2006). SWIP-N's developer, Great Basin, received that adder conditionally in October 2025, effective when it hands its capacity to CAISO's control (193 FERC ¶ 61,083).

Common mix-ups

  • Claim: The certificate means customers will pay whatever the line costs. What the evidence shows: Both the B2H and SWIP-N orders left prudence for later. B2H added a soft cap; SWIP-N made no cost finding at all.
  • Claim: FERC sets Idaho power bills. What the evidence shows: FERC sets wholesale transmission rates. The Idaho PUC sets retail rates, though FERC-set costs and revenues flow into what it reviews.
  • Claim: Transmission is the biggest part of a bill. What the evidence shows: EIA says generation is the largest component of the price of electricity. Transmission matters most at the margin, when several big projects land in rates at once.

Reporting angle

  • When a recovery case is filed for B2H or SWIP-N, compare the requested amount to the estimate in the certificate case. For B2H, any excess over the soft cap needs justification. Find it.
  • Ask for the jurisdictional allocation: what percentage of each project lands on Idaho customers, and by what method.
  • Find the transmission revenue credit in the most recent rate case and ask how it would change with each new line.
  • Read staff production requests in the docket. They often ask the sharpest cost questions.
  • Numbers to check: in-service date, total installed cost, Idaho share, return on equity, depreciation life, and residential dollars per month at a stated kWh.

Research angle

Check yourself

1. What did the Idaho PUC decide about cost recovery when it granted Idaho Power's SWIP-N certificate in December 2025?

2. Which agency sets the rates a utility charges other companies to move power over its interstate transmission lines?

3. A utility adds $140 million of transmission plant. Using a 7.2 percent return, 50-year straight-line depreciation and $3.5 million of operations and taxes, what is the first-year revenue requirement?

4. In the B2H certificate order (No. 35838, 2023), what cost protection did the Idaho PUC set?

5. Why does a utility's rate base shrink each year for the same line?

Terms in this lesson

Certificate of public convenience and necessity (CPCN)
Idaho PUC permission, under Idaho Code 61-526, for a utility to build a line or plant. It does not decide what customers will pay.
Open access transmission tariff (OATT)
A utility's FERC-approved terms and rates for others to use its transmission system.
Jurisdictional allocation
The split of a multi-state utility's costs among the states it serves before each state sets retail rates.
Soft cap
A limit on recoverable cost that the utility can exceed only by proving the extra spending was justified.
Participating transmission owner
A company that places lines under CAISO's operational control and recovers its revenue requirement through CAISO's transmission rates.

Full glossary

Sources