Idaho Public Utilities Commission

Case No. GNR-E-11-03

August 2, 2012

Contact: Gene Fadness (208) 334-0339, 890-2712



Hearings begin Tuesday in renewable power case

The Idaho Public Utilities Commission Tuesday begins what could be three days of hearings over the method used to determine what small-power producers are paid along with other issues.


The case began in late 2010 when Idaho Power Company, Avista and PacifiCorp (Rocky Mountain Power) petitioned the commission to investigate a number of issues related to utility purchases from renewable power developers. Idaho Power claimed it was being forced by federal law to buy wind generation it did not need at rates that were not reasonable for customers.


To encourage renewable power development, Congress in 1978 passed the Public Utility Regulatory Policies Act (PURPA), which requires regulated utilities to buy energy from qualifying renewable small-power projects. Although the “must-buy” provision of PURPA is a federal law, Congress left it to states to determine the rate to be paid producers, called “Qualifying Facilities” (QFs). That rate, called an avoided-cost rate, is to be based on the cost the purchasing utility avoids by not having to generate the power itself or buy it from other sources. Because ratepayers end up paying for the energy their utilities buy from QFs, the intent of the federal law is that, cost-wise, ratepayers be indifferent as to whether their utility uses more traditional sources of power or newly encouraged alternatives.


Utilities argue changes are needed so that energy they are required to buy from renewable projects is more accurately priced so that customers do not end up paying too much for QF-generated energy. Small-power producers generally argue that states are charged by Congress to encourage development of the QF industry and that the proposed changes will discourage independent renewable power development in Idaho.   


The hearing begins at 9 a.m. Tuesday in the commission hearing room at 472 W. Washington St., in Boise and is scheduled to last through Thursday though the hearing may not take that long. The hearing is open to the public.


Parties to the case include the following: Idaho Power, Avista Utilities, PacifiCorp (Rocky Mountain Power), the Northwest and Intermountain Power Producers Coalition, J.R. Simplot Company, Grand View Solar II, Exergy Development Group of Idaho, Renewable Energy Coalition, Interconnect Solar Development, Dynamis Energy, North Side Canal Company and Twin Falls Canal Company, Adams County Board of Commissioners, Birch Power Company, Idaho Windfarms, Blue Ribbon Energy, Renewable Northwest Project, Idaho Conservation League, Snake River Alliance, Clearwater Paper Corporation, Energy Integrity Project, Idaho Wind Partners, Ridgeline Energy, Mountain Air Projects, Big Wood Canal Company, American Falls Reservoir District No. 2 and commission staff.


Here is a summary of some the issues in the case:


Curtailment – Idaho Power proposes a new tariff to establish a process that relieves utilities from mandatory purchase obligations during certain periods of light customer load. Idaho Power claims that federal regulations allow such curtailment to avoid cost increases to customers when the utility must back-down base load units to accommodate QF output and “then suffer an otherwise unnecessary increase in cost when it must use higher-cost power sources during the interval required to ramp base load units back up when higher load conditions resume.”  Renewable developers argue that PURPA allows for curtailment only to meet emergency operational needs, current avoided-cost rates are already adjusted for curtailment, and curtailment amounts to a retroactive modification of existing contracts


Renewable energy certificates – PURPA does not regulate and there is no Idaho state policy regarding who should reap the financial benefits of the RECs or “green tags” associated with QF projects.  Commission staff maintains that if utilities are compelled by federal law to buy energy that is renewable, then the benefits of renewable energy should go with the energy purchased by the utility and its ratepayers. “It is illogical, unreasonable and unjust for ratepayers to pay for what is, in reality, renewable energy through a must-purchase obligation under PURPA, not get the benefit of the renewable attribute that is produced with each kilowatt, and then be required to pay through rates again when the utility purchases RECs,” in order to meet a state or federal renewable portfolio standard,” commission staff states.  Developers argue that RECs should remain with QF developers because they are not compensated for environmental attributes under PURPA provisions that compensate QFs only for energy and capacity. They argue that allowing utilities to own RECs would re-open past agreements and amount to a taking of private property.


New formula to determine avoided-cost – Idaho Power proposes to replace the current method to determine the avoided cost rate to what it calls an “hourly incremental cost” methodology based on the highest-cost displaceable resource (typically a company-owned thermal plant or a long-term purchase contract). The hourly cost is totaled each month to arrive at heavy-load and light-load pricing for each month of the contract term. The utility argues that this method more accurately reflects true avoided-cost. Renewable developers argue that Idaho Power is adopting a “short-run” avoided-cost model and arguing for shorter contract lengths to artificially deflate avoided-cost rates, contrary to federal law.  They say the hourly method is too complex and needs hourly updating, which contributes the utilities’ ability to “game” the system. Further, the formula does not take into account the value of market sales of QF power during times of surplus and wrongly excludes potential carbon costs.


Contract length – Most PURPA contracts are for 20 years. Idaho Power proposes 5 years.



Delay damages and delay security –  Idaho Power argues these damages ($45/kw) should remain a part of QF purchase agreements when a project is more than 90 days beyond its scheduled operating date or defaults entirely.  Developers argue they don’t reflect actual damage to the utility and are punitive.