Generators that may have executed bilateral contracts with a California utility prior to the passage of Assembly Bill 32 (AB 32) in California such that their contract does not have specific terms and conditions assigning greenhouse gas cost responsibility should be aware that the matter of whether the generator is entitled to some sort of relief is going to be decided as part of a California Public Utilities Commission rulemaking (R.11-03-012) with initial comments on the subject due today and reply comments due September 5.
Parties are not required to submit comments today in order to participate in the rulemaking regarding AB 32, but it would probably be a good idea to provide reply comments if they are interested in participating.
On June 21, the California Public Utilities Commission announced that it would be delving into the quixotic world of retail rate design. This incredibly important but amazingly esoteric area of utility regulation will affect just about everyone because it concerns how to split up the pie and who pays how much. Rate design is zero-sum– if you pay less, someone else has to pay more. So needless to say everyone — and I do mean everyone– who pays an electricity bill has an interest in this proceeding.
Just last week, the Commission assigned two different Administrative Law Judges to the proceeding (signalling its high priority and importance) and sent out an agenda related to a first public workshop on August 27 to provide some direction for the proceeding.
Among the major issues to be discussed at the preliminary workshop are:
1) what should be the goals of retail rate design;
2) what are the optimal rate design structures;
3) what equity concerns are there with regard to rate design;
4) what overlap might there be with other current proceedings that should result in some coordination
If you’re interested in tracking or participating in this proceeding, let us know!
The California Public Utilities Commission has been holding a rulemaking since March 2011 to determine what to do with the revenues that utilities will receive as a result of the direct allocation of greenhouse gas allowances to electrical distribution utilities in the state as a result of the new cap and trade program.
As you might expect, various interest groups have very different ideas as to how to spend those new dollars. The utilities and many of the consumer groups have been strenuously arguing that these revenues should flow directly back to ratepayers, while some of the environmental groups have been arguing for setasides from these dollars for various conservation, energy efficiency and renewables programs. As an observer of the Commission proceeding, it seemed like the CPUC was leaning towards complete and direct reimbursement to ratepayers, but no formal ruling or decision making that determination had been made.
But in swoops the legislature. Under Senate Bill 1018, ”the commission shall require revenues, including any accrued interest, received by an electrical corporation as a result of the direct allocation of greenhouse gas allowances to electric utilities pursuant to subdivision (b) of Section 95890 of Title 17 of the California Code of Regulations to be credited directly to the residential, small business, and emissions-intensive trade-exposed retail customers of the electrical corporation.”
So that seems to leave a number of “non-emissions intensive trade-exposed retail customers” out of luck. Large businesses, agriculture, government, etc., are all cut out of the revenues. In addition, Senate Bill 1018 also states:
The commission may allocate up to 15 percent of the revenues, including any accrued interest, received by an electrical corporation as a result of the direct allocation of greenhouse gas allowances to electrical distribution utilities pursuant to subdivision (b) of Section 95890 of Title 17 of the California Code of Regulations, for clean energy and energy
efficiency projects established pursuant to statute that are administered by the electrical corporation and that are not otherwise funded by another funding source.
So rather than having all of the revenues flow back to ratepayers, there will be a 15% set-aside for “clean energy and energy efficiency projects” and the remainder of the revenues will only flow back to residential, small business (whatever that means), and emissions-intensive trade-exposed retail customers (whatever that means).
From our colleague Jim Mitchell in our DC Office.
The Federal Energy Regulatory Commission has proposed to provide developers of new merchant transmission projects and new cost-based, participant-funded transmission projects with increased flexibility to offer terms and conditions of service that may be desired by potential transmission service customers. Under this proposal, transmission developers would be permitted to allocate up to 100% of the capacity in such projects through bilateral negotiations with individual customers relating to the key terms and conditions under which transmission capacity is to be provided. Although the FERC is not proposing to extend such flexibility to incumbent transmission owners, which “have a clearly defined set of existing obligations under their OATTs with regard to new transmission development, including participation in regional planning processes and the processing of transmission service request queues,” it stated that it would review requests by incumbent transmission owners for a waiver of any OATT requirement needed for them to pursue transmission development that is just, reasonable, and not unduly discriminatory.
Current FERC policies permit developers of merchant transmission projects to sell a portion of the capacity on such projects to individual “anchor tenants” at non-cost-based rates established through bilateral negotiations, but require the remainder of the capacity on such projects to be offered to all potential purchasers at standard rates, terms and conditions through an open season solicitation. The proposed policy is intended to enable developers of merchant transmission projects and all potential customers to negotiate mutually-agreeable rates, terms and conditions of service, and therefore to facilitate expansion of the transmission grid in a non-discriminatory manner.
In order to benefit from the flexibility available under the proposed policy, merchant transmission project developers must engage in a broad solicitation of interest in their projects from potential transmission customers, and to submit a report on the details of allocation of capacity after all arrangements had been negotiated. A similar process would apply to non-incumbent developers of new cost-based participant-funded transmission facilities. However, the FERC would review the transmission rates charged by such developers to ensure that they are consistent with FERC policies regarding rates for cost-based transmission service.
To be acceptable to the FERC, the solicitation of interest in a proposed project would need to be widely disseminated and to provide potential transmission customers with detailed information about the technical specifications of the project, proposed contract terms, and criteria to be used by the developer in identifying transmission customers to participate in further negotiations. The merchant transmission project developer could then negotiate details of the arrangements (e.g., points of delivery and receipt, construction schedules, term of service, cost-sharing arrangements) with those customers that are interested in obtaining service and qualified to do so. The policy would permit a single transmission customer to acquire 100% of the transmission capacity available on a particular project in this manner if it desired to do so.
In order to ensure that the process of allocating capacity on new merchant transmission projects is open and transparent and that it is not the result of undue discrimination, the FERC is also proposing to require project developers to submit a report discussing the solicitation process. The report would describe the nature and extent of the solicitation, the criteria used by the developer to identify transmission customers selected to participate in detailed negotiations, and factors affecting a developer’s decision to offer terms to certain customers that are different from those granted to other customers. The report would also be expected to discuss decisions regarding prorating of capacity if the project is oversubscribed and/or the potential for increasing capacity in the project under such circumstances.
In prepared remarks regarding the proposal, FERC Chairman Wellinghoff explained that “this proposal finds the appropriate balance between the flexibility to negotiate rates, terms and amounts of capacity potential customers want, which many developers told us they need to secure financing, with new safeguards to ensure that these rates are not unduly discriminatory or preferential and are just and reasonable.” Similar remarks were offered by Commissioner Philip Moeller. Commissioner John Norris further noted that what he described as the “spaghetti lines” dilemma arising from construction of multiple transmission facilities would be addressed through the requirement that the transmission developer discuss its response in the event capacity on the project is over-subscribed.
The proposal to revise the FERC’s policies for allocation of transmission capacity being developed by non-incumbent transmission owners is contained in a Proposed Policy Statement issued July 19, 2012 in Allocation of Capacity on New Merchant Transmission Projects and New Cost-based, Participant-Funded Transmission Projects, FERC Docket Nos. AD12-9-000 and AD11-11-000, 140 FERC ¶ 61,061 (2012). Comments on the proposed Policy Statement are due to be filed within 60 days after it has been published in the Federal Register.
Proposed Settlement Between Environmental Groups and Federal Agencies Would Revise Procedures for Designation of Western Energy Corridors
From my D.C. colleague Jim Mitchell:
Procedures for designation of West-wide Energy Corridors pursuant to Section 368 of the Energy Policy Act of 2005 are to be revised to allay concerns that (i) construction of energy-related facilities within such corridors would adversely affect environmentally sensitive areas and (ii) that procedures for designation of such corridors improperly support development of new coal-fired generation resources while failing to give appropriate consideration to transmission needs of generating stations utilizing renewable energy resources that could be developed in the future. Such procedures are to be modified in accordance with a recent Settlement Agreement between the United States government and several environmental groups which was filed on July 3, 2012 in The Wilderness Society, et al. v. United States Department of the Interior, et al., No. 3:09-cv-03048-JW (N.D. Cal).
Section 368 of the Energy Policy Act of 2005 requires the Federal government to designate corridors for development of oil, gas, and hydrogen pipelines and electricity transmission and distribution facilities on Federal land in the eleven states in the West (Arizona, California, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington, and Wyoming), and to expedite applications for authorization to construct or modify oil, gas, hydrogen pipelines and electricity transmission and distribution facilities within such corridors. The Wilderness Society and other environmental groups challenged regulations adopted to implement this requirement following the designation of more than 6,000 miles of such corridors in 2008. According to a press release issued by the Wilderness Society, the original corridor designations did not “facilitate access to renewable energy development,” and “would adversely affect National Park Service areas, National Monuments, National Wildlife Refuges, habitat for threatened and endangered species, and proposed wilderness,…and miss opportunities to minimize impacts and designate preferable locations.”
The Settlement Agreement is subject to approval by the United States District Court. When effective, the Settlement Agreement requires that the future revision, deletion, or addition to the system of corridors designated pursuant to Section 368 of EPAct 2005 be based on consideration of the following general principles:
- Location of corridors in favorable landscapes that provide maximum utility while minimizing the impact to the environment.
- Promotion of efficient use of the landscape for necessary development.
- Facilitation of renewable energy projects where feasible by providing connectivity to renewable energy generation to the maximum extent possible.
- Avoidance of environmentally sensitive areas to the maximum extent practicable.
- Diminution of the proliferation of dispersed rights-of-way crossing the landscape, and improvement of the long-term benefits of reliable and safe energy transmission.
The Settlement Agreement requires the Bureau of Land Management, the Forest Service and the Department of Energy to adopt specified open and transparent processes for designation of such corridors which provide an opportunity for stakeholder involvement, and to provide appropriate training and supervision for personnel responsible for administering the processes. In addition, it requires authorities to review certain existing corridors in (i) northeastern California and northwestern Nevada, (ii) southern California southeastern Nevada, and western Utah, and (iii) southern Wyoming, northeastern Utah, and northwestern Colorado, to ensure that they are consistent with the agreed-upon principles, especially with regard to efficient use of the landscape. These West-wide Energy Corridors should not be confused with National Interest Electric Transmission Corridors established pursuant to Section 216 of the Federal Power Act in which the Federal Energy Regulatory Commission may approve construction of interstate electric transmission facilities under certain circumstances if state regulatory authorities fail to do so.
FERC Proposes to Revise Definition of “Bulk Electric System” for Determining Who Must Comply with Federal Reliability Standards
From my D.C. colleague Jim Mitchell:
The Federal Energy Regulatory Commission (FERC) has issued a Notice of Proposed Rulemaking (NOPR) to revise the definition of “Bulk Electric System” (BES). This definition is important because it determines which transmission system elements are subject to mandatory electric reliability standards designed to ensure the uninterrupted operation of the electric grid. Owning or operating a facility that is within the BES definition imposes compliance obligations subject to audit, and failure to remain in compliance can result in substantial economic penalties. In addition to proposing a revised definition of BES, the NOPR proposes an “exception” process whereby entities could ask that specific facilities be included or excluded. All entities owning or operating electric facilities that may impact the integrated transmission network should review this NOPR to see how it might affect their reliability obligations.
For more information on this subject, please see DWT’s recently issued advisory by Brian Gish of our Washington, D.C. office.
According to California Energy Markets, a number of environmental justice groups filed a complaint on June 8 with the EPA challenging CARB’s cap and trade program. The groups appear to include the same organizations that filed an earlier complaint in San Francisco Superior Court.
The arguments appear to be different. In the court action, the plaintiffs are challenging the offset portion of the cap and trade program, arguing that offsets may be used to satisfy an impermissibly large portion of a regulated entity’s compliance obligation. In the EPA complaint, the complainants are apparently arguing that CARB has focused insufficiently on reduction of emissions at the source, resulting in further disadvantaging minority communities located in proximity to emitting sources subject to cap and trade. The groups allege that the cap and trade regulations violate the Federal Civil Rights Act of 1964 and ask that EPA make federal financial support contingent on changing the focus of the cap and trade regulations to emission reductions at the source.
All this while many of these same groups are supporting a bill in the Assembly (AB 2563) that would provide a process for adopting new offset protocols.
Lots of action in the world of cap and trade.
From our colleague Tim Cunningham:
Prop 65 continues to grow with the addition of a natural and commonly manufactured chemical used in many products including model airplane glue. California’s Office of Environmental Health Hazard Assessment (OEHHA) has added methylisopropyl ketone to the Proposition 65 list. Proposition 65, also known as the Safe Water and Toxic Enforcement Act of 1986, requires the state to list chemicals that are known to cause cancer or reproductive toxicity. Methylisopropyl ketone, an industrial solvent, was listed as causing reproductive toxicity.
Listing of a chemical generally requires a company doing business in California to provide a warning before exposing anyone to a chemical on the list, and to prevent discharging listed chemicals into any sources of drinking water. Business have 12 months from the listing date to comply with warning requirements, and 20 months to comply with discharge requirements. In recent years Prop 65 has been criticized as encouraging nuisance claims against small businesses and allowing warnings to become too commonplace to have meaning.More information on Proposition 65 listings, requirements, and compliance is available on OEHHA’s Proposition 65 website.
In a huge win for the solar industry, the California Public Utilities Commission voted unanimously to issue a decision that clarifies the calculation of the California’s five-percent Net Metering cap. Net Metering (“NEM”) allows customers to earn credit for excess solar electricity they produce that is distributed to other customers on the grid.
Electric utilities are only obligated to offer Net Metering to customers until the amount of installed solar capacity equals five percent of the utility’s “aggregated customer peak demand.” Prior to the CPUC’s decision, electric utilities interpreted “aggregate customer peak demand” to mean the coincident system peak demand, or the highest demand from all customers at any one time. Under this interpretation, many utilities would not accept new Net Metering customers potentially as soon as 2013 and the viability of rooftop solar would be severely threatened.
The CPUC decision clarifies that aggregate customer peak demand means the aggregation, or sum, of individual customers’ peak demands. This clarification doubles the amount of solar systems that can benefit from Net Metering, providing the benefits of solar energy to many more customers — a huge win for the solar industry.
CPUC Opens New Proceeding on Impacts of Net Metering
However, the CPUC decision also opens a proceeding to examine the costs and benefits of Net Metering for non-participating customers and consider possible revisions to the Net Metering program. This will have a huge impact of the continued success of the solar industry in California and bears close monitoring.
New Net Metering rules must be adopted by January 1, 2015 or the Net Metering program will be suspended.
FERC Denies Preference for Reservation of Transmission Capacity on Merchant Transmission Line for Renewable Energy Resources
From my DC colleague Jim Mitchell
Rock Island Clean Line LLC is proposing to build a 500-mile, 600 kV HVDC merchant transmission line and associated facilities capable of delivering up to 3,500 MW of capacity and associated energy from generation projects in eastern South Dakota, eastern Nebraska, western Iowa and western Minnesota to customers in Illinois and other states. In a November 2011 application to the Federal Energy Regulatory Commission, Rock Island sought authorization to sell up to 75% of the capacity in its transmission line to credit-worthy anchor tenants at negotiated rates, with the remainder of the capacity to be sold through an open season.
Rock Island noted in its application that its transmission line was intended to facilitate the delivery of energy from renewable energy resources in the Midwestern United States to major load centers, and asserted that use of the line for that purpose would reduce potential opposition to construction of the transmission line. It therefore proposed to give a preference during the open season to entities seeking to reserve capacity for delivery of energy from renewable energy resources by scoring proposals premised on the transmission of electricity from renewable resources more highly than proposals to transmit energy from non-renewables.
In an order issued on May 22, 2012, the FERC authorized Rock Island to allocate 75% of the planned capacity in the project to anchor customers in order to foster development of the project. However, the FERC rejected Rock Island’s proposal to grant a preference in its open season to entities proposing to transmit energy from renewable resources. In so doing, the FERC concluded that Rock Island had not provided a sufficient explanation of how distinctions between renewable energy resources and other types of generators justified the preferential treatment of renewable energy resources in an open season for reservation of transmission capacity.
Also in the order, the FERC denied a request by Rock Island for waiver of the obligation to comply with Parts 41 and 101 of the FERC’s regulations, relating to the maintenance of books and records in accordance with the Uniform System of Accounts. The FERC explained that although it had previously waived the applicability of those regulations to other merchant transmission line developers, denial of Rock Island’s request for a waiver was appropriate in order to facilitate its regulatory oversight. The order was issued in Rock Island Clean Line LLC, 139 FERC ¶ 61,142 (2012), and is available on the FERC’s website (www.ferc.gov)