United States: Energy Industry Updates For January 2011

FERC Denies Rehearing and Affirms Order on California's Feed-In Tariff Proposal

FERC recently clarified federal preemption issues involved with state feed-in tariff programs in an order denying a rehearing request by several California utilities and the Edison Electric Institute (EEI) regarding California's proposed feed-in tariff program. The decision confirms that states can combine their authority to set avoided cost rates with their authority to set energy procurement requirements for state utilities. This combination allows states to set avoided cost pricing with reference to a specific class of generators, essentially permitting the development of certain types of feed-in tariffs.

The California utilities argued that no notice was provided to the public that avoided cost pricing and/or the effect of purchase mandates on such pricing would be the subject of the case. The California utilities also objected to FERC's determination that the concept of a multi-tiered avoided cost rate structure could be consistent with the avoided cost rate requirements set forth in the Public Utility Regulatory Policies Act (PURPA) and the FERC regulations.

FERC denied rehearing and rejected the arguments proposed by the California utilities and EEI. FERC confirmed that it was only providing guidance on the approaches the California Public Utilities Commission (CPUC) proposed to take, and was not ruling on whether the CPUC's actual offer price under the proposed program was, in fact, consistent with the avoided cost requirements of PURPA.

FERC noted that it was not required to proceed by rulemaking on this issue, but had the discretion to proceed by case-specific adjudication, which both the CPUC and the California utilities requested.

On the issue of whether appropriate notice had been given, FERC stated that the utilities themselves had previously raised arguments in the proceeding pertaining to avoided cost rates, and thus those utilities "cannot persuasively claim that they did not have notice that issues pertaining to avoided cost rates may be addressed ... ."

FERC reaffirmed its previous decision and held that because avoided cost rates are defined in terms of costs that an electric utility avoids by purchasing capacity from a qualifying facility (QF), and because a state may determine what particular capacity is being avoided, the state may rely on the cost of such avoided capacity to determine the avoided cost rate. Thus,

By reaffirming its previous decision, FERC's actions provide clarity to states seeking to develop and implement feed-in tariffs as a way to encourage renewable energy generation development. Though FERC has not yet ruled on the specifics of California's proposed program, this proceeding provides states with guidance to construct their own programs in a way that avoids preemption by federal law.

Congress Extends the Section 1603 Cash Grant Program

Only a few weeks before the program was set to expire, Congress acted on the widespread pleas from the renewable energy industry to extend Section 1603 of the American Recovery and Reinvestment Act of 2009 (Section 1603). In addition to other energy-related provisions, Congress included a one-year extension of Section 1603 in the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act). On December 17, 2010, President Obama signed the Tax Relief Act into law.

Section 1603 provides cash grant payments in lieu of investment tax credits (ITCs) for specified energy property. The Tax Relief Act extended the deadline for the commencement of construction of specified energy property from December 31, 2010 to December 31, 2011. However, the Tax Relief Act did not extend the placed-in-service deadlines for such specified energy property, which range from January 1, 2013 for large wind facilities to January 1, 2017 for solar and small wind projects. Thus, projects that will commence construction in 2011 have a shorter timeline to be placed in service than previously provided under Section 1603.

The Tax Relief Act also created new tax benefits and extended several current tax benefits applicable to renewable energy projects. Notably, the Tax Relief Act extended the availability of bonus depreciation for qualified property and increased the incentives under the bonus depreciation framework. Like Section 1603, the bonus depreciation provisions were set to expire at the end of 2010. However, the Tax Relief Act extended such provisions for two years. Furthermore, the bonus depreciation amount was increased from 50 percent to 100 percent for qualified property placed in service after September 8, 2010 and before January 1, 2012, provided that the taxpayer had not entered into a binding written contract for such property prior to January 1, 2008.

Massachusetts Recognizes Benefits of Price Suppression, Other Factors in Approving Cape Wind PPA

Cape Wind notched several major milestones in 2010. Approval of its power purchase agreement with National Grid by the Massachusetts Department of Public Utilities (MDPU) occurred November 22. This approval followed the long-awaited announcement of federal approval of Cape Wind's proposed 468 MW offshore wind project in Nantucket Sound by the U.S. Secretary of the Interior in April 2010, and subsequent signing by Cape Wind of the first commercial lease for an offshore wind project issued by the federal government in October 2010.

Cape Wind's PPA commits National Grid to purchase 50 percent of the energy, capacity, and renewable energy credits (RECs) associated with the project for a period of 15 years following commercial operation. The bundled price for energy, capacity, and RECs under the PPA is $187/MWh, commencing in 2013 and escalating by 3.5 percent on January 1 of each year thereafter. The price assumes that the wind generation facility is placed in service on a date when the facility qualifies for the investment tax credit (ITC) established pursuant to Section 48 of the U.S. Internal Revenue Code, regardless of whether the tax credit is claimed. The PPA provides for price adjustment in the event the facility does not qualify for the ITC. The PPA also provides for adjustments in the event that the project exceeds the target net capacity factor of 37.1 percent (a "Wind Outperformance Adjustment Credit") and/or if Cape Wind receives any payments or credits for contract capacity sold in the Forward Capacity Market. The PPA also includes a provision allowing National Grid to extend the contract beyond 15 years at a potentially reduced price.

The MDPU decision approving the Cape Wind PPA notably grants approval despite concluding that the contract could increase the bills of National Grid residential customers by roughly 1.3 to 1.7 percent, and the bills of large commercial and industrial customers by roughly 1.7 to 2.2 percent, when other, less expensive renewable energy resources are available. However, MDPU also concludes that Cape Wind project offers significant benefits that are not currently available from any other renewable resource, and that these benefits outweigh the costs of the project.

In considering the cost of the proposed contract to customers, MDPU includes the effect of price suppression, which MDPU believes will offset at least some of the contract's above-market costs to National Grid's customers, and reduce prices for all of the other electricity customers in the state and the region. MDPU anticipates that price suppression will result when Cape Wind bids into the wholesale energy market at zero cost, on account of zero fuel costs, thereby establishing a lower energy price in the wholesale market. Although there were differing views on the magnitude and duration of the price suppression effect, all the parties to the proceeding agreed that there would be a downward effect on market prices in general as a result of the contract.

Balancing the overall cost of the contract are numerous "unquantified" benefits, according to MDPU. These include the following:

• Assisting National Grid and the Commonwealth to comply with (i) the state's renewable portfolio standard, which requires 15 percent of the state's electricity supply to come from renewables by 2020, with an additional one percent requirement each year thereafter; (ii) the state's Global Warming Solutions Act, which requires a reduction in greenhouse gases of (1) 10 percent –25 percent by 2020 and (2) 80 percent by 2050, with interim target levels in 2030 and 2040; and (iii) the state's Green Communities Act, which establishes a goal of meeting 20 percent of the state's electric demand through renewable and alternative energy generation by 2020. Given these requirements, as well as the similar requirements of neighboring states, MDPU concludes that the demand for renewable resources during the next 15 to 20 years will far outstrip the current supply. In considering the practical limitations on the development and potential scale of alternative renewable resources in the region, MDPU determines that development of offshore wind resources is the only viable means to achieve these statutory requirements.
• Enhancing electric reliability in the state, due to its location and fuel source. The Cape Wind project will interconnect at a point very close to the largest electricity loads in New England, which MDPU concludes is advantageous from a reliability standpoint, especially compared to typically more remote renewable resources in transmission-constrained areas. As for the project's "fuel," MDPU notes that wind is especially plentiful in the winter, when natural gas is at a premium for heating purposes.
• Moderating system peak load, due to (i) higher expected capacity factors of offshore wind facilities, with greater coincidence to both summer and winter peak loads, than onshore wind or solar facilities, and (ii) the fact that Horseshoe Shoal, where the project will be located, has one of the strongest and most consistent wind regimes in New England.
• The creation of additional employment. MDPU concludes that the net positive impact of the contract on job creation will be 162 new jobs per year for the 15-year term of the contract. MDPU also cites a number of studies that conclude that the project overall will have a positive impact on long-term employment and on resulting economic activity in the region.

MDPU's analysis of the costs and benefits of Cape Wind's offshore wind energy contract will likely establish precedent for evaluation of future alternative energy supply arrangements, especially in jurisdictions where cost relative to other available resources has been the driving consideration. However, in most cases, public utility commissions are statutorily constrained in the scope of factors they may consider in conducting a review of proposed power supply arrangements. MDPU's authority to conduct the cost-benefit analysis it relied upon in reaching its decision was granted under Section 83 of Massachusetts' Green Communities Act. Before we see a widespread adoption of the approach taken by MDPU, legislative initiative will be required, taking action to broaden the "unquantified" benefits of renewable energy contracts that public utility commissions may consider in reaching their decisions.

The California Energy Commission Approves Molten Salt Solar Storage Facility

The California Energy Commission recently approved a permit for Rice Solar Energy, LLC, a subsidiary of SolarReserve, LLC, to build a 150-MW molten salt solar energy storage facility, which will be located 30 miles from Blythe, California. The project has a 25-year power purchase agreement with Pacific Gas & Electric (PG&E). The project was approved on December 15, 2010, and would be California's first molten salt solar storage facility.

Molten salt solar storage technology works by reflecting sunlight from a group of tracking mirrors (heliostats) to a receiver located on top of a central tower. The heliostats are focused on the receiver as they track the sun during the day. The receiver collects the concentrated sunlight and uses it to heat molten salt (a mixture of sodium and potassium nitrate) to more than 1,000 degrees Fahrenheit. The molten salt then goes into a thermal storage tank, where it can be sent to conventional steam turbines for power generation. The molten salt is then returned to a thermal storage tank to repeat this cycle.

According to SolarReserve, the project still must receive approvals from both the California Bureau of Land Management and the Western Area Power Administration. If approved, construction would begin in the first quarter of 2011, startup testing in the first quarter of 2013. Commercial operation is expected to begin by the third quarter of 2013.

Molten salt solar storage is emerging as an interesting component of the energy storage picture. Earlier this month, SolarReserve received approval from the U.S. Department of the Interior for a 100-MW molten salt solar storage facility in Nevada, the Crescent Dunes Solar Energy Project, and environmental permits from the state of Arizona for a proposed 150-MW molten salt solar storage power plant 70 miles southwest of Phoenix.

New York PSC Approves Sharing Customer Utility Data Without Prior Customer Consent

The New York Public Service Commission (New York PSC) has approved the transfer of customer utility data to a third-party vendor without prior customer consent for the purpose of conducting energy efficiency programs. The New York PSC's order last month reversed an earlier ruling in which it approved the use of energy efficiency behavior modification programs administered by OPower for Central Hudson Gas & Electric Corporation (Central Hudson), but required that Central Hudson receive prior individual customer consent to the use of their customer usage data in the programs.

OPower's energy efficiency programs aim to incentivize utility customers by sending them personalized reports comparing their energy usage to those of similarly situated customers. OPower argued that the design requires access to personally identifiable customer information including names, addresses, and individual customer usage data and does not provide customers an opportunity to grant informed consent prior to the transfer of their personal information from the utility to OPower. After receiving the information and notifying those program participants who will receive the reports, the participants will have the opportunity to "opt-out" from receiving the reports. However, their data will already have been transferred to OPower and will continue to be used in the energy efficiency program.

Many jurisdictions require that customer data not be shared with third parties unless the customer has consented in advance. The New York PSC nevertheless approved the data sharing with OPower, concluding 1) that the contractual privacy obligations between the utilities and OPower were sufficient to protect customer privacy interests; 2) that providing customer data to OPower did not constitute a "sale" of customer data under New York law; 3) that OPower will be using the customer data solely for the use of administering the energy efficiency programs, which the New York PSC viewed and a rate-payer-funded utility function; and 4) that the customer data was necessary to successfully implement the energy efficiency programs.

The issue of third-party access to customer utility data is hotly debated, particularly in light of the evolution of the smart grid and smart meter programs. It remains to be seen whether other jurisdictions will adopt the position of the New York PSC on this issue.

FERC Issues Related Orders on Market-Based Rate Affiliate Restrictions and Sharing of Employees

A recent pair of related orders provide caution to public utilities with captive customers who also have affiliates with market-based rate authority: Employees who determine the timing of scheduled outages, or who engage in economic dispatch, fuel procurement, or resource planning, may not be shared absent a company-specific waiver. In the orders, FERC denied rehearing of an April 15, 2010 order clarifying market-based rate affiliate restrictions and withdrew a notice of proposed rulemaking (NOPR) that would have amended FERC's regulations on affiliate restrictions.

In Order No. 697, FERC adopted affiliate restrictions between franchised public utilities with captive customers and their power sales affiliates with market-based rate authority. Order No. 697 required that the employees of power sales affiliates must operate separately from employees of the affiliated franchised utility, with exceptions for certain categories of employees who may be shared, and governed the sharing of market information, sales of non-power goods or services, and power brokering. These restrictions apply as a condition of receiving market-based rate authority unless explicitly granted a waiver by FERC.

The April 15 order responded to a request for clarification of the market-based affiliate restrictions. In that the order, FERC found that employees who determine the timing of scheduled outages, or who engage in economic dispatch, fuel procurement, or resource planning, may not be shared. In denying the EEI's request for rehearing, FERC affirmed that its finding was not a departure from FERC precedent. FERC stated that EEI was seeking to relitigate FERC's findings in Order No. 697 and 697-A regarding the sharing of employees. FERC emphasized that only those employees included in the specific categories of shared support employees (such as legal, accounting, and field and maintenance employees) could be shared by a market-based affiliate and a franchised public utility with captive customers. FERC retained its authority to review on a case-by-case basis circumstances in which affiliates seek to share employees or market information. Only those entities that apply for, and are granted, waivers may share employees. The order requires seller to comply with the guidance in the April 15 order within 90 days.

In an order issued concurrently, FERC withdrew an NOPR that proposed to amend regulations covering market-based rate affiliate restrictions. The proposed regulatory language stated that employees who determine the timing of scheduled outages or who engage in economic dispatch, fuel procurement, or resource planning may not be shared under the market-based rate affiliate restrictions codified in Order No. 697. FERC stated that it was withdrawing the NOPR because the current regulations are sufficient as they require employees of a market-regulated power sales affiliate to operate separately from the employees of any affiliated franchised public utility with captive customers, to the maximum extent practical.

Mandatory Qualifying Facility Purchases and Legally Enforceable Obligations Reviewed

The Energy Policy Act of 2005 (EPAct 2005), as implemented by FERC under Order 688, allows public utilities, under certain circumstances, to apply to terminate their obligation to enter into power purchase agreements with qualifying facilities (QFs). For example, FERC established a rebuttable presumption that larger QFs (those with generating capacity in excess of 20 MW) with access to the energy markets maintained by Midwest ISO, PJM Interconnection, ISO New England, and New York ISO could not force utility companies to purchase their output.

Since Order 688, FERC decisions have clarified the circumstances under which a QF's existing petition for a legally enforceable obligation will be given effect even after a utility company's obligation to purchase power from QFs is otherwise terminated.

Most recently, FERC reexamined its April 15, 2010 order that granted in part an application by the Public Service Company of New Hampshire (PSNH) to terminate its mandatory purchase obligation, but determined that PSNH would remain obligated to purchase electricity from Clean Power Development, LLC (Clean Power). Clean Power had already submitted a petition to create a legally enforceable obligation to the New Hampshire Public Utilities Commission (PUC). In denying PSNH's request for rehearing, FERC on January 20, 2011, explained that it had not, in its April 15 order, determined that there was a legally enforceable obligation. Rather, FERC clarified that "if as a result of Clean Power's petition before the New Hampshire Commission there was a contract or legally enforceable obligation, then it would be grandfathered." Consequently, although PSNH's obligation to purchase electricity from other large QFs was terminated, it would nonetheless be required to buy from Clean Power if the New Hampshire PUC determined to grant a legally enforceable obligation.

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