Long Island Power Authority Announces New And Expanded Clean Solar Initiative Feed-In Tariff Program
The Long Island Power Authority (LIPA) recently announced its Clean Solar Initiative Feed-In Tariff-II (FIT-II), a feed-in tariff program for solar projects between 100 kW and 2 MW in size and located in LIPA’s service territory. FIT-II is currently open for public comment, and will be effective only upon formal approval by the LIPA Board of Trustees.
FIT-II is capped at 100 MW, and follows the first version of the Clean Solar Initiative Feed-In Tariff (FIT-I). Unlike FIT-I, projects will not be selected for participation in FIT-II on a first-come, first-served basis. Instead, all applications submitted within the application period will be evaluated; those that pass a preliminary screening process of technical and administrative review will be eligible for further consideration under a Clearing Price Auction mechanism.
Each application will include a price bid ($/kWh) for energy to be delivered from the proposed project. Those applications that pass the initial screening will be ranked in order of bid price, and the lowest-priced projects will be accepted for FIT-II participation, subject to the overall program capacity cap. The highest price bid among the accepted projects will the “Clearing Price,” and all accepted projects will be awarded 20-year power purchase agreements at the Clearing Price. In addition, projects located in the South Fork will receive a price premium of $0.07/kWh (detailed eligibility requirements for the premium are provided by LIPA).
Subject to program approvals, LIPA expects to take FIT-II applications from September 30, 2013, through January 31, 2014. By the end of the year, LIPA is expected to issue two additional renewable energy initiatives: A 20 MW feed-in tariff and an RFP for up to 280 MW of renewable energy.
More information, including FAQs, is available on LIPA’s FIT website.
In the wake of the extension of the production tax credit, my colleague Ed Einowski has analyzed a key challenge – the relative scarcity of available utility-scale power purchase agreement RFPs. Having a PUC-approved PPA in place is generally a prerequisite for securing financing for utility-scale wind projects. Here’s what he has to say:
The extension of the production tax credit (PTC) allows the wind energy industry to move forward with projects in 2013. But the last few years – especially 2012 – have seen relatively few utility-scale wind power purchase agreements executed. Without the assured revenue source of a power purchase agreement (PPA), wind projects will generally find third-party financing – whether debt, tax equity or cash equity – unavailable. And few developers – even those with the financial resources to do so – will likely be willing to risk proceeding with project construction in the absence of a financeable PPA. As a consequence, for most developers the PTC extension presents the immediate challenge of securing a financeable PPA to enable the PTCs to be secured. Given the time it generally takes to negotiate and finalize a utility-scale wind PPA as well as pursue other key items such as turbine supply agreements and engineering, procurement and construction contracts, it will be necessary to move expeditiously.
For a more detailed discussion of the issues involved, read the full article.
Citing changes in market conditions, Southern California Edison (SCE) announced last week that it is beginning the process of reforming the standard Power Purchase Agreement (PPA) it uses for its California Renewable Energy Small Tariff (CREST) program. CREST is SCE’s feed-in tariff program for eligible renewable energy projects under 1.5 MW. The PPA for each of these projects is a standard, non-negotiable PPA under either a full buy/sell or excess power purchase program for a term of 10, 15, or 20 years. Of the 247.7 MW allocated to SCE by the California Public Utilities Commission (CPUC) for CREST, SCE states that it has 214.1 MW either under contract or in the queue.
In its press release, SCE states that it will publish the proposed pro forma PPA on its website on June 2. It also states that the proposed “CREST PPA is based on SCE’s pro forma Solar Photovoltaic Program PPA for projects less than 5 MWs, and has been modified to make it applicable to all technology types and to be in compliance with the requirements of the CREST Tariff and CPUC Decision (‘D.’) 07-07-27.” Comments on the proposed PPA will be due by June 22, with the submission of the new PPA to the CPUC planned for August 2011.
On July 27, 2010, the Court of Appeals of Texas, Fifth District, Dallas, issued its decision in TXU Portfolio Management Company, L.P., v. FPL Energy, LLC, et al., 2010 Tex. App. Lexis 5905 (2010). The case arose when three FPL wind farms (the "Wind Farms") located in the McCamey area of West Texas experienced ERCOT-imposed generation curtailments imposed by the Electric Reliability Council of Texas ("ERCOT") during 2002-2005. The Wind Farms had each entered into a power purchase agreement (“PPA”) with TXUPM under which they agreed to deliver a minimum quantity of energy and renewable energy credits (RECs) each year. Because of the deficiencies caused by the ERCOT generation curtailments, TXUPM sued the Wind Farms for deficiency damages under the PPAs. The Wind Farms counterclaimed, asserting that TXUPM materially breached each of the PPAs by failing to insure enough "transmission capacity" to allow the three wind farms to generate and deliver all of the electricity they were theoretically able to generate given wind conditions.
Section 2.03 of the PPAs required TXUPM to arrange for "all services, including without limitation Transmission Services . . . necessary to deliver Net Energy." The Texas Court of Appeals concluded that this provision required TXUPM to supply transmission service sufficient to accept delivery of energy actually generated by the project and delivered to the interconnection point. Contrary to the Wind Farms' argument, however, Section 2.03 did not require TXUPM to make sure there was enough transmission capacity in the McCamey area to make sure that the three wind plants could in fact generate every MWh they were theoretically capable of generating given wind conditions.
This outcome is not too surprising--it would have been very unusual had the Court of Appeals concluded that an offtaker's duty to supply transmission services at the delivery point amounted to an implied duty to arrange for the construction of (very expensive) transmission infrastructure sufficient to avoid generation curtailments. Utilities everywhere can breathe a sigh of relief that the Court of Appeals did not read this duty into the PPAs.
The fact that the Wind Farms had failed to deliver enough output to meet the annual minimum quantities specified in the three PPAs was not in dispute. Since the court concluded that TXUPM had not breached the PPAs by failing to supply transmission capacity, the only remaining question was the calculation of damages.
Stepping away from the court’s decision for a moment, though, it’s worth noting that there's a separate provision that is typically included in PPAs for intermittent renewable energy, and it apparently was not included in the three PPAs in dispute here, perhaps because of their 2000-2001 vintage. An annual minimum output guarantee requires a wind developer to take both mechanical availability risk and wind risk--the plant's output can be reduced below the minimum level if the wind doesn't blow as hard or as often as expected, or if the wind turbines and other equipment are not available as often as they should be. However, these risks are to some extent within the developer's control--wind risk can be addressed by thorough wind studies, and mechanical availability can be managed using the developer’s O&M program. Generation and transmission curtailment, on the other hand, are typically outside the developer's control and can be affected by delays in completing transmission infrastructure, additions of other intermittent resources to the grid, routine maintenance of the transmission system, emergencies and other factors.
Recognizing this, renewable energy PPAs usually provide that curtailed energy is counted as if it were generated for purposes of determining whether a plant has achieved its output guarantees. Although the requisite language is often omitted from utility pro forma renewable PPAs, most utilities are willing to agree if pressed that energy that could have been generated but for curtailment(s) should be counted as if it were generated for purposes of testing the project’s output guarantee. There may be a little scuffling over the proper method for calculating the quantity of energy and RECs that would have been generated “but for” the curtailment, but the real fight is usually over whether the PPA is in whole or in part a "take or pay" contract in which the utility is required to pay for some or all of the output that is actually curtailed. Cf. FPL Energy Upton Wind I, L.P., v. City of Austin, 240 SW3d 456 (2007), reh’g denied 2007 Tex App LEXIS 9306 (Tex App Amarillo 2007) (the Texas Court of Appeals ruled that ERCOT-imposed curtailments are not the same as voluntary economic curtailments by the power purchaser under a PPA and thus are not curtailments that the purchaser must pay for).
In any case, the Wind Plants in this case did not receive credit for curtailed energy under the three PPAs, so the court considered the deficiency as a given and turned to calculating the amount of damages. The three PPAs had hard-wired $50/MWh as the liquidated damage payment due for each MWh of deficiency below the annual output guarantee. This number was based on the per MWh penalty the Texas PUC was expected to impose, as of the time the PPA was entered into, on utilities that failed to secure enough renewable energy. The Wind Plants argued that this amount bore no resemblance to TXUPM's cover damages at the time of the alleged breach and had persuaded the trial court to declare the liquidated damages clause to be unenforceable. The Texas Court of Appeals reversed, concluding that the Wind Farms had failed to prove (1) that a measure of damages was ascertainable when the PPAs were entered into, or (2) that the $50/MWh rate was an unreasonable estimate of TXUPM's actual damages.
Using the deficiency rate of $50/MWh and the Wind Farms' total net deficiencies of 580,465 MWh for 2002 through 2005, TXUPM claimed $29,023,250 in deficiency damages. Bear in mind that these are just the deficiency damages, and thus only a part measure of the pain the plants suffered--they also had to forego a sale at the contract price and lost a Production Tax Credit (PTC) on each MWh curtailed. For utilities that are slow to acknowledge that curtailment risk is an important issue for the intermittent energy developer, this case offers a very succinct $29 million dollar explanation of why developers, lenders, and equity care so much about the topic.
From our colleague Michael O'Connell:
On May 18, 2010, California and the Federal Energy Regulatory Commission (FERC) signed a Memorandum of Understanding (MOU) to coordinate federal and state procedures and schedules for development of hydrokinetic projects off California’s coast. FERC previously entered MOUs for such coordination with Oregon, Washington and Maine.
The California-FERC MOU provides that the parties will encourage developers to seek pilot project licenses prior to a full commercial license. The footprint and number of devices deployed in California waters for testing would be limited under pilot project licenses in order to minimize environmental risk. FERC’s 2008 hydrokinetic pilot project white paper provides that pilot licenses would be issued for five years in order to allow licensees to conduct device testing and monitoring in support of studies required by applications for longer-term licenses. The California-FERC MOU also provides for consultation with stakeholders on the design of studies and other environmental matters.
According to the MOU, permits, leases and licenses issued by California agencies will require technology performance reporting and study results together with safeguards to ensure that projects will not have significant adverse effects on environmental, economic or cultural resources. The MOU parties also agree to share information from project developers regarding their facility’s energy production and “if applicable, power purchase contracts awards, during a project’s licensing application process and/or license term; provided that dissemination of the information is not otherwise protected from disclosure.” These MOU provisions are likely to raise confidentiality concerns among developers. The MOU recognizes that FERC cannot issue a license for a hydrokinetic project within California marine waters unless certain concurrences are issued or waived that a project is consistent with California’s Coastal Management Program. Any license issued by FERC will include, to the maximum extent practicable, terms and conditions determined by California agencies to be necessary to avoid, minimize and mitigate damage to fish, wildlife, and public trust resources.
The California-FERC MOU confirms state support for development of wave energy projects that can play a significant role in meeting the California’s goal of producing 33 percent of its electricity from renewable energy by 2020.
On May 14, 2010, Salt Lake County, Utah will be releasing a Request for Proposals (“RFP”) for a 1 MW solar project. If your company is interested in receiving the RFP as soon as it is released, you should register with BidSync (registration is free).
About the Solar Project:
It is anticipated that the initial solar project will include three County facilities (Salt Palace Convention Center, Environmental Health, and the Riverton Senior Center) with solar installations totaling approximately 1 MW. This solar project will utilize a power purchase agreement (“PPA”) financing model. It will also employ public and private capital, Federal grants, and public/private subsidized bonds that are able to work together efficiently because of the recent Stimulus Bill. The project also makes use of recent changes to Federal tax rules, and the recent re-awakening of private capital markets that make a significant public-private partnership possible. The County is working to coordinate these financial resources to make them easily accessible. More details will be available in the RFP. Longer term, Salt Lake County Mayor Peter Corroon has set a goal to install 10 MW of solar on as many county-owned facilities as possible.
PPAs and Third-Party Financing Now an Option in Utah:
In 2010, with the passage of HB 145 – Renewable Energy Financing Provisions, Utah enabled third-party financing of renewable energy systems for the following entities: a county, municipality, city, town, other political subdivision, local district, special service district, state institution of higher education, school district, charter school, or any entity within the state system of public education; an entity qualifying as a charitable organization under 26 U.S.C. Sec. 501(c)(3) operated for religious, charitable, or educational purposes that is exempt from federal income tax and able to demonstrate its tax-exempt status. Significantly, this recent legislation clarified that certain third-party financing arrangements are exempt from regulation by the Utah Public Service Commission, which is consistent with how these arrangements are viewed in several other states across the country. This clarification will now open the door for more innovative financing for renewable energy technologies, which has the ability to remove the upfront cost hurdles of capital intensive investments and offer an attractive bundle of services, including: design, installation, financing (including monetizing tax benefits), permitting and interconnection, maintenance, etc.
U.S. Supreme Court Rules that Third-Parties Challenging Energy Contract Rates Must Clear the Mobile-Sierra Hurdle
Today, the U.S. Supreme Court issued an important ruling clarifying how the Federal Energy Regulatory Commission (FERC) must apply the Mobile-Sierra doctrine. The Mobile-Sierra doctrine informs how FERC should evaluate whether a contract rate for energy is just and reasonable, and the doctrine provides that FERC's sole concern should be whether the contract rates being challenged adversely affect the public interest--a high hurdle. Until today, some people questioned whether the Mobile-Sierra doctrine was limited to parties to a contract, and whether non-contracting parties bringing a challenge would be held to a lower standard. The Court, however, made clear that the Mobile-Sierra doctrine should apply to any party (including FERC) challenging whether energy rates are just and reasonable, stating that a presumption that applies to contracting parties only, but not anybody else, fails to establish the contractual stability that Mobile-Sierra aimed to secure.
To read more about today's U.S. Supreme Court decision, click here.
Public Service Commission of Utah Investigates Third-Party Power Purchase Agreements For Renewable Energy Generation
On October 12, 2009, the Public Service Commission of Utah ("PSC") joined the ranks of several other states in the west, including Oregon, when it established a docket to investigate whether, and the extent to which, certain third-party arrangements for renewable energy generation are subject to the PSC's jurisdiction. www.psc.utah.gov/utilities/misc/miscindx/0999912indx.html, Pursuant to the notice, the PSC may consider the following issues:
- Whether the third-party is a public utility under Utah law;
- Whether the third-party is a public utility under Utah law when arrangements are entered into primarily as a financing mechanism for distributed renewable energy generation systems whereby a third-party owns the renewable generation equipment, which is installed on a utility customer's premises, there is a long-term contract with the customer to supply a portion of that customer's electricity use, and payments are based on kilowatt-hours;
- Whether the third-party is a public utility under Utah law when (i) there is a single relationship between the third-party owner of the generation and a customer or (ii) there are multiple customers taking power from the same third party;
- Whether the third-party is a public utility under Utah law when arrangements involve the leasing of distributed generation equipment from non-utility lessors to lessees that are also retail customers of utilities.
Comments and/or legal briefs regarding the above issues must be filed with the PSC by November 16, 2009. A technical conference to discuss the specific terms and conditions surrounding third-party financing arrangements and other issues will be held on November 23, 2009, at 1:30 p.m. to 4:00 p.m., Fourth Floor Hearing Room Room 401, Heber M. Wells State Office Building, 160 East 300 South, Salt Lake City, Utah.
SCE Solar PV Program:
Back in June, the California Public Utilities Commission (“CPUC”) issued a decision authorizing Southern California Edison (“SCE”) to execute contracts for up to 250 MW of generation from solar PV facilities owned and operated by independent power producers through a competitive solicitation process. The CPUC decision required SCE to file an advice letter outlining the criteria for selection of bids and containing a draft standard power purchase agreement (“PPA”).
SCE recently filed the requisite advice letter requesting approval of its proposed competitive solicitation process and criteria and a draft standard PPA. Anyone may file protests or responses to SCE’s advice letter. Protests are due on August 10, 2009. For more information, as well as a link to SCE’s draft standard PPA, go to the CPUC website.
CPUC Panel on Feed-in Tariffs:
The CPUC announced that it will host an interactive panel discussion on feed-in tariffs for renewable energy on August 27, 2009. The panel will feature international experts from Germany, Spain, the United States, and elsewhere with experience in the global solar power market. The panelists will offer their insights on the global solar market, the role of feed-in tariffs and other mechanisms for advancing renewable energy development, and California’s role in facilitating wholesale renewable distributed generation.
The panel will be held from 1-2:30 PM at the CPUC Auditorium, 505 Van Ness Ave., San Francisco, CA.