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.

The state Board of Public Utilities (“BPU”) would administer credits to wind energy producers for each megawatt of electricity generated by offshore wind farms.  The producers can then sell the credits to offset production costs of offshore wind projects.  The bill also would allow the state to provide up to $100 million in tax credits for qualified wind energy facilities in wind energy zones. 

However, opponents of the bill argue that the unknown costs of these energy credits could raise customers’ electric bills.  The legislation allows wind developers to apply to the BPU to establish a fixed price for the credits over twenty years, with adjustments for inflation.  Once the price is established, the state cannot reconsider the issue.  Opponents also point out that similar proposals in Virginia and Kentucky have failed due to the high projected costs.

S 2036 passed by a 28-10 vote in the state Senate, and a 71-6 vote in the state Assembly, with one abstaining vote.  The bill has been presented to Governor Chris Christie to sign, and Christie has spoken favorably about the bill in the past.  If the Governor signs the bill into law, then several proposed offshore wind projects could receive even more financial support from the state.  For example, in 2008, the state awarded Garden State Offshore Energy a $4 million grant for a 350-MW offshore wind facility.  Additionally, Fishermen’s Energy of New Jersey LLC is proposing a two-phase 370-MW project off the coast of Atlantic City.
 

A copy of the bill is available here

The CAISO Board of Governors adopted the new transmission plan to address the transmission needs of generating 33 percent of energy from renewable sources by 2020.  The new transmission planning process adopts a statewide approach, and will consolidate all ISO planning activities in order to move away from the single-project approach.  However, the CAISO Board exempted from the new requirements those state renewable projects that are scheduled to complete construction deadlines under the American Recovery and Reinvestment Act. 

The new transmission planning process is divided into three phases.  In Phase 1, CAISO and other participants in the California Planning Group will develop a conceptual statewide transmission study plan for access to renewable resources.  In Phase 2, the CAISO planners will perform the economic planning studies required under the study plan and finalize the comprehensive statewide transmission plan.   CAISO will designate each of the specific projects of the transmission plan as either a Category 1 or Category 2 element.  Category 1 transmission elements are those the CAISO has a high level of confidence are needed to connect renewable energy to the grid, based on sufficient commercial interest from new generation, or are economically justified.  Category 2 projects are those that are potentially needed, but cannot be approved without further evidence of commercial interest.  During Phase 3, the ISO will receive proposals to build Category 1 projects.

The CAISO Board’s new reliability requirements have been controversial because they would apply the FERC Order No. 661-A Standard for Voltage and WECC Criteria for Frequency to intermittent resources.  CAISO said it is necessary that renewable generation meet the same voltage and reactive power requirements as conventional fossil-fuel generation to maintain reactive power, which is vital for an alternating current transmission structure.  Also, CAISO now will require all new resources to be equipped with fault ride-through capabilities to minimize tripping and down time when a fault occurs.  Finally, CAISO approved a series of generation power management requirements in order to interconnect to the grid.

CAISO expects to file the tariff changes by June 1, 2010 with FERC for approval of the new transmission planning process and other requirements.

The CAISO memos on the revised transmission plan and new requirements are available at http://www.caiso.com/2793/2793ad662d310.pdf and http://www.caiso.com/2793/2793abee1a0a8.pdf.

The Project consists of a 2,000 megawatt (“MW”) underwater and underground electric transmission system with two 1,000 MW High Voltage Direct Current (“HVDC”) circuits.  These circuits would travel from the Canadian border to two different points.  One circuit would travel to Yonkers, New York, connect with a converter station owned by Champlain, and eventually connect to a substation in Manhattan by way of a 345 kV Alternating Current cable system.  The other circuit would follow a similar path initially, but instead of exiting the Hudson River, it would travel into the Long Island Sound and eventually connect to a converter station in Bridgeport, Connecticut.  The lines would be sited either underwater or underground. 

Champlain’s Application requested appointment of a hearing officer “as soon as practicable” before July 1, 2010.  Champlain stated that they are attempting to qualify for a $2,300,000,000 loan guarantee from the U.S. Department of Energy (“DOE”).  In order to qualify for a DOE loan guarantee, Champlain must fulfill the DOE’s “commencement of construction” requirement by September 30, 2011. 

Since the Application was filed, several parties have filed motions to intervene and requests for active party status in the above-referenced matter.  In addition to the NYPSC, the Connecticut Department of Public Utility Control, and the Federal Energy Regulatory Commission (”FERC” or the “Commission”) will also have to approve the Project.  

A full copy of Champlain’s application can be found here

Under the federal Clean Air Act, Colorado must submit a regional haze plan by early 2011, or the Environmental Protection Agency will write a plan for the state.  HB 1365 will allow utilities in Colorado to develop their own plans for meeting the regional haze guidelines, as well as the standards for ozone, mercury, and carbon dioxide.  The law also requires investor-owned electric utilities in the state to cut nitrous oxide emissions from coal-fired plants by up to 80% by the end of 2017. 

Critics opposed the bill, arguing that it would take away jobs from coal miners and unfairly favor natural gas producers.  However, the bill passed with support from Xcel Energy Inc.’s Chairman and CEO, who stated that the new law would allow the state to comply with the Clean Air Act’s regional clean air standards requirement in a more cost effective manner.  Supporters also said the new law would create jobs by replacing older technology with cleaner energy sources.

Xcel Energy has agreed to work with the Colorado Department of Public Health and Environment to submit an Emission Reduction Plan by August 15, 2010 to the Colorado Public Utilities Commission (“Colorado PUC”) that will specify how the company will retire or retrofit at least 900 MW of coal-fired generation.  The plan will focus on converting or replacing those coal plants with natural gas, renewables, and other cleaner fuel supplies. 

The law also allows utilities to fully recover the cost of expenses incurred executing an approved Emission Reduction Plan, including the costs for planning, developing, constructing, operating, and maintaining any emission control or replacement generation facilities.  If a utility is subject to rate regulation by the Commission and sells power on the wholesale market, the Colorado PUC can assign some of the plan’s costs to wholesale customers, as long as there is no conflict with existing wholesale contracts.  The utility must then apply to FERC for recovery of such costs from its wholesale customers.  If FERC does not allow recovery of costs assigned to wholesale customers, then the Colorado PUC will reassign those costs to be recovered through retail rates. 

Governor Ritter said he hopes the new law will serve as guidance to the rest of the country for reducing air pollution.

The text of the legislation is available here