PG&E Issues Its 2012 Renewables Portfolio Standard Request for Offers
At long last, PG&E finally issued its 2012 Renewables Portfolio Standard (RPS) Request For Offers (RFO). PG&E is seeking offers to procure approximately 1,000 GWh per year of renewable energy from long-term Power Purchase Agreements and Renewable Energy Credit Purchase Agreements (so they will accept offers of products that would qualify for any of the three portfolio content categories).
However, PG&E has a “strong preference” for products from projects that commence renewable energy deliveries to PG&E beginning in 2019-2020. PG&E also “prefers Offers for Product that is eligible to be counted toward Category 1 procurement for the purpose of the RPS Program.” The 2012 Solicitation Protocol can be found here.
The schedule for the RFO:
| PG&E Issues RFO | December 10 | |
| Deadline for Participant to submit registration for Bidders’ Webinar | December 17 by 5:00 P.M. PPT | |
| Bidders’ Webinar | December 20 at 10:00 A.M.- Noon PPT | |
| Deadline for Submission of Offers | January 29, 2013 by Noon PPT | |
| PG&E selects shortlist | April 1, 2013 | |
| Execution of Final Agreements and Submit for CPUC Approval | TBD | |
| PG&E 2012 RPS Solicitation Shortlist Expires | April 17, 2014 |
More information, documents and schedules is available on PG&E’s website.
CleanPowerSF: Political Correctness Trumps Energy Policy
Read what my colleagues Steve Greenwald and Jeff Gray have to say about why CleanPowerSF is an exercise in political correctness in the latest edition of Power Magazine.
My favorite quote and teaser: ”CleanPowerSF represents yet another Balkanizing, politically motivated misadventure in energy policy.”
FERC Suspension of Market-Based Rate Authority May Affect Existing Power Supply Arrangement
From our colleague Jim Mitchell in DC:
The authority of J. P. Morgan Ventures Energy Corporation (“JP Morgan”) to sell electric energy, capacity, and ancillary services at market-based rates for six months, beginning in April 2013, was recently suspended by the Federal Energy Regulatory Commission (the “FERC”) for violation of certain FERC rules.
Although the Order only affects the market-based rate authority of JP Morgan, the FERC is currently conducting an investigation of other alleged violations of FERC rules that may result in further suspension of market-based rate authority of JP Morgan and its affiliates.
In the Order, the FERC concluded that JP Morgan had provided false or misleading information and omitted material information in communications with the FERC and with the California Independent System Operator, Inc., in violation of Section 35.41 of the FERC’s regulations, 18 CFR § 35.41(b). The FERC explained that the effectiveness of the suspension was being deferred until next April in part to afford JP Morgan time to make alternative arrangements to fulfill any existing contractual obligations that may be affected.
The Order indicates that JP Morgan will not be permitted to charge market-based rates for electricity supplied during the suspension period, even where contracts containing market-based rates were negotiated prior to the effective date of the suspension. Instead, JP Morgan may file for cost-based rates pursuant to which it could sell energy, capacity, and ancillary services during the suspension period. Although JP Morgan is also permitted to bid capacity and energy into organized wholesale power markets, the rates at which such electricity is offered will be restricted.
However, market-based rates for sale of electricity pursuant to a market-based rate power sales tariff on file at the FERC generally are deemed to be just and reasonable. Montana Consumer Counsel v. FERC, 659 F. 3d 910 (9th Cir. 2011). The Supreme Court ruled in Morgan Stanley Capital Group, Inc. v. Public Utility District No. 1 of Snohomish County, Washington, 554 U.S. 527 (2008), that the mere fact that a party engaged in unlawful activity in the spot market would not deprive its forward contracts of the benefit of the Mobile-Sierra presumption that such contracts are just and reasonable, and that “[t]here is no reason why FERC should be able to abrogate a contract [on the grounds of unlawful activity] without finding a causal connection between unlawful activity and the contract rate.” Because there is no indication of a causal connection between the alleged violation of the FERC’s rules which resulted in the suspension and negotiated rates being charged by JP Morgan, it is at least arguable that JP Morgan should be able to continue to collect market-based rates established in existing contracts which were negotiated prior the suspension of its market-based rate authority.
JP Morgan may file a request for rehearing of the Order (under the FERC’s rules, JP Morgan has 30 days from issuance of the Order in which to file a request for rehearing), and thereafter seek appellate review of the Order. Unless there is a stay of the Order, the Order presumably will remain in effect at least until the conclusion of the appellate review process. Therefore, the final outcome of the suspension process may not be known for many years.
In order to resolve any uncertainty regarding rates to be charged by JP Morgan during the suspension period under contracts containing market-based rates that were negotiated prior to the effective date of the suspension, JP Morgan and the counter-parties to those contracts may desire to negotiate a mutually-acceptable accommodation. Failure of the parties to do so may result in potentially costly litigation regarding the continued effectiveness of a power sales agreement once the suspension becomes effective, and/or regarding damages to be paid for premature termination of a contract.
One possibility might be for the parties to agree to modify the rights and obligations of the parties to engage in power sales transactions during the suspension period and/or to specify revised rates at which such electricity would be sold by JP Morgan. Such an accommodation would provide each party with certainty regarding the role of JP Morgan as a power supplier during the suspension period, and would enable purchasers to make alternative power supply arrangements if the supply of electricity from JP Morgan was to be reduced. Another possibility might be for the parties to negotiate arrangements under which JP Morgan will continue to supply power during the suspension period at cost-based rates permitted by the FERC, but to provide for a retroactive adjustment of such rates in the event that the Order is modified or reversed during the appellate process. Finally, if purchasers have long-term market-based rate contracts with JP Morgan that they believe are particularly advantageous, they may desire to have the FERC exempt such contracts from the suspension requirement.
First Cap and Trade Auction Results
The California Air Resources Board (CARB) released the results from the first California CO2 emissions allowance auction held last week. CARB’s initial assessment is that the auction was a success. It went off without any electronic glitches and there was no evidence of tampering or interfering with the market. As a procedural matter, it was a success. For complete results, see http://www.arb.ca.gov/cc/capandtrade/auction/auction.htm. The levels of activity and expense were not as robust as CARB had anticipated, however.
The sale price for the 2013 allowances was not as high as CARB expected or as markets predicted. The allowances were all sold at $10.09 each. The minimum actual reserve price was set at $10.00. The “auction” rewards allowances from highest bid to lowest bid, but the price on the lowest bid applies to all of the allowances sold at that auction. Therefore, even though the highest bid was $91.13, all bidders paid $10.09 per allowance. Many people expected the allowances to sell for about $12-$13 each.
All of the 2013 vintage allowances were sold — 23,126,110. CARB received bids for three times that number of allowances. (Since a participant can offer more than one bid, it cannot be said that one in three participants received allowances.)
The auction also included vintage year 2015 allowances. Only about 5.5 million out of the approximately 40 million available, about 15%, sold. The auction price on the 2015 allowances was $10.00.
As a key part of the California’s Global Warming Act, or AB 32, the cap and trade program relies on allowances as permits to emit CO2 and other greenhouse gases. The program sets a limit, a cap on total emissions, which reduces yearly. Emitters must surrender allowances, one allowance per metric ton of CO2 or CO2 equivalent. There should exist a secondary market where emitters can buy extra allowances which others do not need, or purchased in order to sell on the secondary market. Those looking to buy and sell in this market will watch the allowance price closely.
Participation in the auction illustrates that (1) participants are taking seriously the obligation to obtain allowances; but that (2) they may be wary of the future of the program given the court challenges to the cap and trade auction. In essence, participants seem to be dipping their toes in the water, perhaps wading in a little bit, but are not yet ready to take the plunge and buy large quantities covering the future.
California GHG Emissions Auction Part of the Cap and Trade Program Challenged by the Chamber
California’s largest business lobby filed a lawsuit yesterday seeking to invalidate California’s first greenhouse gas (GHG) emissions allowance auction (part of the California cap and trade program) scheduled for today. The California Chamber of Commerce asserts that AB 32, California’s global warming law, did not authorize the state to raise funds by allocating GHG emissions allowances to itself and to auction them off to raise revenues for the state to use. The chamber characterizes the auction as an unconstitutional tax as well as a violation of AB 32.
The chamber filed the lawsuit in Sacramento Superior Court but did not seek an injunction to stop today’s auction. Rather the lawsuit seeks to enjoin the California Air Resources Board (CARB) from allocating to itself GHG emission allowances and then selling them through an auction process. The complaint and petition for writ of mandate can be found here. It is unclear what result might be achieved if today’s auction is successful and the chamber prevails on its complaint. Subsequent auctions are scheduled quarterly.
Approximately 10 percent of the GHG emission allowances are reserved to CARB to be sold. The chamber asserts in its complaint that all of the GHG emission allowances should be allocated to business for free and to allow companies that exceed their allowance to purchase GHG emission allowances from other companies. The chamber concludes that its interpretation of AB 32 will fulfill the state’s goal of reducing emission while keeping costs low for business and consumers.
The chamber argues that AB 32 only authorized CARB to impose a “minor administrative fee” and did not expressly authorize CARB to raise revenue by selling GHG emission allowances. Additionally, because two-thirds vote is required to raise taxes, requiring businesses to purchase GHG emission allowances is an unconstitutional tax imposed on some businesses. A copy of the Memorandum of Points and Authorities in Support of Verified Petition for Writ of Mandate and Complaint for Declaratory Relief can be found here.
CARB estimates that about $1 billion may be raised from the sale of allowances in fiscal year 2012-2013. California law dictates that CARB must place any money it raises to a special GHG reduction account and any programs that use the funds must be consistent with AB 32’s GHG reduction goals. The complaint states that the Governor’s 2012-2013 budget assumes that $500 million from CARB’s auction can be used to offset General Fund costs. The chamber estimates that over the span of the program, through the year 2020, auction revenues could range from $12 billion to more than $70 billion.
Auction Today, Results Monday (part of the California Cap and Trade Program)
Get your auction here! Today is the day.
The California Air Resources Board (CARB) is holding an auction of greenhouse gas allowances for use in the California cap and trade program today, November 14, 2012, from 10:00 a.m. until 1:00 p.m (PST). It is CARB’s first auction and all eyes are on California to see how it goes. Everyone is curious to see the prices and other details.
The results of the auction won’t be available until Monday November 19, however. At 12:00 noon (PST) CARB will publish the results on its website. Take a look then:
http://www.arb.ca.gov/cc/capandtrade/auction/auction.htm
California’s Cap and Trade Allowances Auction: Canary in a Coal Mine
California holds its first Cap and Trade Allowances auction on Wednesday November 14, 2012. Some see this as a make-or-break time, the test case to see if a Cap and Trade program for greenhouse gas emission allowances can get off the ground. The first auction was originally scheduled for August 2012. Some industry groups are urging Governor Brown to put the brakes on this Wednesday’s auction, but as of this writing no such order has been offered.
The California Air Resources Board (CARB) will hold the auction between the hours of 10:00 a.m. and 1:00 p.m. (PST) on Wednesday November 14, 2012. Approximately 63,000 allowances relating to 2013 through 2015 will be on the auction block. The minimum price will be $10 per allowance, which is significantly higher than the emission allowances traded in the East Coast’s Acid Rain program involving power plants, called the Regional Greenhouse Gas Initiative (RGGI).
Before bidding on allowances, a participant must be registered with CARB and its bids must qualify by meeting other rules and standards. The Notice for this auction, which includes those requirements, is located at http://www.arb.ca.gov/cc/capandtrade/auction/november_2012/auction_notice_updated.pdf
All eyes are on California with the pundits waiting to assess the success or failure of the program. California is the Canary in the Coal Mine.
California Public Utilities Commission to Consider New Proposals to Improve Renewables Portfolio Standard Procurement Process
On Oct. 5, 2012, Commissioner Mark Ferron of the California Public Utilities Commission (“Commission”) issued a 39-page ruling including a number of proposals to improve California’s Renewables Portfolio Standard (“RPS”) procurement process. Specifically, he proposed an:
[E]ffort to streamline the RPS contract review process, increase the transparency of the Commission’s review of RPS procurement, establish clear standards for this review process, issue Commission determinations on contract reasonableness on a defined timeline, and generally, to support market certainty in RPS procurement.
The ruling requests comments and input from interested parties and poses specific discussion questions for each of the proposals and issues. Commissioner Ferron’s ruling also offers stakeholders in the RPS procurement process and California renewable energy markets an important opportunity to address deficiencies that almost all participants have endured in the RPS procurement process and suggest improvements.
Given the statements of various Commissioners in the last few months regarding the need for change in the RPS procurement process, the Commission may never be as receptive to “constructive criticism” from stakeholders regarding the RPS procurement process as they are right now. Comments are due Nov. 20, and reply comments must be submitted by Dec. 12, 2012.
Background
The ruling explains that improvements to the RPS procurement process are necessary to better ensure market certainty. To provide context, the ruling notes a number of major changes that have taken place in the California renewable energy markets over the past couple of years:
- A 250 percent increase in the number of bids and a 150 percent increase in the number of developers in the 2011 RPS solicitation as compared with the 2009 RPS solicitation.
- The total amount of renewable energy generation bid into the 2011 RPS solicitation is 4.5 times greater than the total compliance need under the RPS.
- The average bid price of RPS projects decreased by approximately 30 percent between the 2009 and 2011 solicitations.
Given these major changes, the Commission will endeavor to make process improvements that will increase efficiency and transparency.
Specific proposals included in the ruling
Commission Ferron seeks comment on a number of specific proposals relating to RPS procurement.
Proposal 1 – Review IOU shortlists via a Tier 3 Advice Letter
After receiving bids in response to their RPS solicitations, investor-owned utilities (“IOUs”) create a shortlist that meets their Commission-approved evaluation criteria. Currently, these shortlists are approved at the staff level by the Commisison’s Energy Division. The IOUs then proceed to negotiate with bidders on their shortlist and then submit final executed contracts for approval by the full Commission.
Commissioner Ferron proposes approval of the IOUs’ shortlists by resolution of the full Commission. By putting more emphasis on the review of the shortlist, the proposal hopes to streamline the later contract review process and, presumably, to minimize regulatory uncertainty regarding the approval by the Commission of an executed contract that does not meaningfully differ from the project as bid.
Proposal 2 – Establish date certain for request for Commission approval of contracts
Currently, there are no specific deadlines for when RPS contracts must be executed or when IOUs must request Commission approval for the executed RPS contracts. The proposal would require RPS contracts be executed within one year of Commission approval of the IOU shortlist and filed with the Commission for approval within one month of the date such contracts are signed.
Proposal 3 – Expedited review of certain RPS purchase and sales contracts
The Commission has attempted an expedited review process for various types of RPS contracts with extremely limited success. The ruling proposes a pair of new expedited review processes.
- 1.) Contracts with terms of less than five years be approved by the Commission at the staff level through the Energy Division via an expedited Tier 1 Advice Letter if certain specific conditions are met:
- Generation quantity consistent with IOU’s net short;
- Contract selected from competitive solicitation or bilateral negotiations and has equivalent or better market value than recently executed similar contracts;
- Use of pro forma contract; and
- Commencement of delivery within one year of execution of the RPS contract.
- 2.) Contracts with terms of greater than five years that use commercially proven technologies would be approved by the Energy Division via an expedited Tier 2 Advice Letter, if certain conditions are met:
- Generation quantity consistent with IOU’s net short;
- Contract selected from competitive solicitation;
- Use of pro forma contract;
- Delivery consistent with procurement need in IOU’s RPS procurement plan, and;
- Project viability criteria.
Proposal 4 – Improve standards of review for other RPS contracts
RPS contracts that do not meet the new conditions for expedited Tier 1 or Tier 2 review summarized above would continue to be subject to full Commission review via Tier 3 Advice Letter. However, the ruling also proposes alternate standards of review for evaluating three different types of RPS contracts: 1) contracts from a solicitation; 2) bilaterally negotiated contracts; and 3) contract amendments and/or amended and restated contracts. All other RPS contracts must be submitted for Commission approval via an application and subject to different review criteria.
Proposal 5 – New standard of review for RPS contracts for unbundled renewable energy credits
The ruling proposes a new standard of review for contracts for the purchase of unbundled renewable energy credits (“RECs”). This standard also would apply to IOU sales of excess RPS-eligible procurement that do not qualify for the expedited approval processes outlined in Section C above.
Proposal 6 – New independent evaluator report template
The ruling proposes specific evaluation criteria that would be included in the report template of the independent evaluator on an IOU’s RPS solicitation, evaluation, and selection process.
Other issues
In addition to the specific proposals, the ruling also seeks comment on the implementation on the new least-cost best-fit requirements included in Section 399.13(a)(4) of the Public Utilities Code, as well as the continued need for the non-modifiable standard term and condition regarding “green attributes.”
Renewables Portfolio Standard Rulemaking to Continue
Having dispensed with many of the preliminary issues regarding the new and improved 33% by 2020 Renewables Portfolio Standard, Commissioner Ferron issued a new scoping ruling on Wednesday providing a preliminary list of issues for the remainder of the proceeding.
The scoping ruling extends the proceeding for another two years, however no specific procedural guideline is provided and the scoping ruling does not even give parties an opportunity to comment on the list of issues.
Still, Commissioner Ferron does identify the five generic topics that he deems as the most significant to address moving forward:
1) Consideration, approval, and relevant revision of 2012 RPS procurement plans
2) RPS procurement issues more generally
3) Improvements to least cost best fit methodology and evaluation of bids for RPS procurement
4) Implementation of statutory requirements for a procurement expenditure limitation methodology for RPS procurement of IOUs
5) Continued implementation of the feed-in tariff
The ruling also provides some sub-topics and explanation regarding each of these more generic topics.
Essentially, this scoping ruling puts parties on notice as to what the issues for the remainder of the proceeding will be, but asks them to “stay tuned” for a more precise procedural schedule.
California to Explore Residential Rate Design
Residential rates and rate design have traditionally been a bit of a “sacred cow” in California that regulators have simply chosen not to mess with. But no more.
On Monday, I attended the first workshop in the new residential rate design rulemaking at the Commission (R.12-06-013) that is aimed at determining the appropriate policy directives in setting a new residential rate design for customers in California.
As you might expect, numerous stakeholders are affected by this rulemaking. Obviously California’s electric utilities are directly affected, and also unsurprisingly, every single ratepayer advocacy organization seems to be participating. More recently, environmental groups have also started to participate in these proceedings as a way to further their mission to ensure overall energy conservation and establishing specific environmental enhancement metrics related to energy policies, including rate design.
Strangely absent, however, are the myriad companies that are developing smart grid technologies specifically aimed at further enabling the conservation activities that are supposed to occur as a result of intelligent rate design.
These companies should participate to seek to ensure that an appropriate rate design in California is created that continues to provide a meaningful incentive to customers to seek to conserve power (and thus make their products and services more valuable); and 2) ensuring that the rate design is not so complex or otherwise inappropriate such that it renders their current platforms and products unusable or incompatible.
Those interested in participating should contact a DWT professional to talk about the best ways for them to effectively participate.
