Despite months of effort, Senate Democrats have been unable to unite in support of a cap-and-trade program or a renewable standard.  A renewable standard requiring utilities to provide 15 percent of their power from renewable sources by 2021 was a key provision in an “energy-only” bill the Senate Energy and Natural Resources Committee approved last year with support from both Democrats and Republicans.  Nonetheless, Senator Reid has decided that he lacks the requisite 60 votes to pass either this standard or a cap-and-trade program.

In addition to the oil spill response provisions, the energy package that Senator Reid says he will push also includes provisions for the creation of clean-energy jobs through the “Home Star” energy efficiency retrofit program, tax incentives for manufacturing of vehicles that run on natural gas, and investments in the Land and Water Conservation Fund.  Reid suggested that many of the bill’s provisions may be based on language from previously-introduced bills; the oil spill response provision, for example, will likely rely heavily on bill S. 3305, sponsored by Senator Robert Menendez (D-NJ), which raises a company’s maximum oil spill liability amount from the $75 million cap set out in the Oil Pollution Act of 1990 to $10 billion. 

Most observers think that cap-and-trade and likely the renewable standard are now unlikely to move in this Congress.  Congress will only have a short session when it returns from the August recess before it adjourns for the elections.  Some have speculated that Congress might take up these issues in a lame duck session after the elections.

In Order No. 2003, the Commission stated that it would allow independent system operators such as Midwest ISO to propose alternative cost allocation methodologies for network upgrades related to generator interconnection.  Midwest ISO subsequently implemented their cost allocation methodology through Baseline Reliability Projects (“RECB I”) and the Regional Beneficial Projects (“RECB II”).  However, some Midwest ISO stakeholders were not satisfied with RECB cost allocation rules, so the Midwest ISO created a RECB Task Force to consider modifications for the cost allocation process. 

Midwest ISO’s instant filing was made after nineteen months of meetings between the Midwest ISO, special interest groups, and stakeholders and transmission owners.  MVPs are defined as “projects that enable the reliable and economic delivery of energy in support of documented energy policy mandates and address, through the development of a robust transmission system, multiple reliability and/or economic issues affecting multiple transmission zones.”  The MVP cost allocation is unique because its costs will be shared through a postage stamp rate to all load in, and exports from, Midwest ISO’s region, based on system usage.  Although initially considered, the Midwest ISO decided not to include a provision that required generators to pay 20 percent of the costs for new MVP lines. 

In addition to the new MVP category, Midwest ISO requested that Generator Interconnection Projects (“GIPs”) that closely follow other GIPs that require network upgrades will share some of the cost of those upgrades.  The Midwest ISO states that these new cost allocation provisions will resolve “first mover/late comer” issues associated with network upgrades.   

The Midwest ISO also requested to retain some cost allocation principles already approved by the Commission.  Notably, reliability projects that are small and local in nature can only recover costs from local customers.  Additionally, the new cost allocation methodology will continue to require generators to pay for all interconnection costs for lines 345 kV and less.  For larger lines, generators must pay 90 percent of the interconnection costs, while the remaining 10 percent is paid by all Midwest ISO customers. 

Proponents for renewable energy believe aggressive cost allocation measures are necessary to connect remote generation to the grid.  However, other parties argue that these costs are unfair to customers within the region, especially for lines that ship the electricity to customers outside the region or state.  Several state officials also believe that aggressive cost allocation measures would significantly increase the prices for electricity customers within their state. 

The proposed revisions to the Midwest ISO’s tariff are available at FERC’s website under Docket No. ER10-1791, and a link to the transmittal letter from Midwest ISO’s proposal is available here.

The Commission previously found that no market manipulation had occurred during specified transactions occurring in 2008 where power was scheduled into PJM Interconnection, L.L.C. (see July 24, 2009 edition of the WER).  The Commission ordered market operators in New York and the surrounding regions to come up with long-term solutions to the “market distortions and increased congestion” as a result of these transactions.  The Commission approved NYISO’s temporary solutions on August 21, 2008, and on July 16, 2009, required NYISO to continue work on solutions. 

NYISO developed the report along with other Regional Transmission Organizations, Independent System Operators and the North American Electric Reliability Corporation.  It includes different items to address loop-flow concerns, installation of Michigan-Ontario phase angle regulators (“PARs”) and long-term market solutions.  The report indicates that the PARs can alter flow paths to better follow the contract path and influence the amount of circuitous flows.  The report also deals with the issue of cost allocation for the Michigan-Ontario PARs and states that NYISO and its stakeholders do not want to pay the International Transmission Company’s (“ITC”) costs for the PARs as they were not the result of a Commission-approved regional planning process. ITC is in charge of installing the Michigan-Ontario PARs. In its conditional approval, the Commission seeks additional information from ITC about how it would operate the PARs without this funding from parties outside ITC. 

The report also recommends implementing four market initiatives: (1) the buy-through congestion proposal; (2) the congestion management/market-to-market coordination proposal; (3) interface pricing revisions; and (4) enhanced interregional transaction coordination.  Commenters challenged the buy-through congestion proposal as an “all or nothing” proposal that would leave market participants without the ability to limit congestion payments to keep their transactions flowing.  The buy-through congestion proposal is the subject of further Commission inquiry. 

The Commission conditionally accepted the NYISO report, with the condition that the parties answer questions set forth by the Commission regarding PAR funding, Buy-Through Congestion and other issues.

A copy of the Commission’s order can be found here.

Earlier this year, the California legislature passed Assembly Bill 1613 (“AB 1613”), the Waste Heat and Carbon Emission Reduction Act, which mandates that regulated investor-owned utilities (“IOUs”) offer to buy power from CHPs at a price to be set by the CPUC.  The CPUC required IOUs to submit 10-year standard purchase contracts (“feed-in tariffs”) for qualifying CHP generators.  To qualify for the minimum price, a CHP generator may not have a generating capacity greater than 20 MW, and the facility must meet certain environmental and efficiency guidelines.  The CPUC order implementing AB 1613 stated that it is not setting wholesale prices for power sales, but only is requiring utilities to offer to buy CHP power at a CPUC-set price designed to reduce greenhouse gas emissions and encourage an increase in CHP generation.

Several utilities sought rehearing of the CPUC implementation order, claiming the CPUC violated the Supremacy Clause and the FPA by attempting to set wholesale prices for energy, a power reserved for FERC.  The CPUC denied rehearing and explained that they are exercising jurisdiction over the utilities’ procurement practices, not trying to govern the conduct of the CHP generators.  A group of utilities and the CPUC both sought declaratory orders from FERC on whether the CPUC is preempted by federal law in this matter.

In its declaratory order, FERC stated that the CPUC implementation order was preempted by the FPA because it sets rates for wholesale power in interstate commerce.  However, FERC went on to state that the CPUC could require the feed-in tariffs be set at avoided cost rates without being preempted by the FPA as long as the CHP generators qualify as QFs (which most do) under PURPA.  FERC did make the caveat that its declaratory order does not address whether the CPUC’s offer price is inconsistent with the avoided cost rate requirement in section 210 of PURPA. 

FERC also stated that the CPUC is not preempted from requiring IOUs to purchase power from non-QF CHPs, but the CPUC may not set wholesale rates for those generators.  Non-QF CHP facilities that want to participate in the state program must file its wholesale rates under FPA Section 205 with FERC. 

Finally, FERC clarified that although public agency wholesale generators are generally exempt from FERC’s jurisdiction, FERC does have authority over their distribution-level facilities and feed-in tariffs pursuant to the FPA.

FERC’s order is expected to fuel considerable debate.  In response to the FERC declaratory order, the National Association of Regulatory Utility Commissioners (“NARUC”) adopted a resolution to allow its staff to advocate before FERC for its position that individual states should be allowed to determine whether public utilities within a state should be required to offer to buy power at prices set by a state commission. 

The full opinion is available on FERC’s website under dockets EL10-64 and EL10-66 and here.

Sacramento Municipal Utility District, the Imperial Irrigation District, the City and County of San Francisco, and the San Diego Gas & Electric Company appealed to the D.C. Circuit.  The appeals related to three areas: (i) the incorporation of marginal loss charges into locational marginal prices, (ii) a new local resource adequacy requirement, and (iii) a congestion revenue rights mechanism. 

The DC Circuit turned away appeals, upholding FERC’s orders approving the changes embodied in the MRTU initiative.  The Court generally deferred to FERC’s findings and considerations of the various arguments put forth.  The full decision can be obtained at www.pacer.cadc.uscourts.gov/common/opinions/201007/07-1208-1256931.pdf