Benton REA Report

Benton Rural

Electric Association

Federal PURPA Standards March 2009

Contents 1. Introduction..........................................................................................................................1 Energy Policy Act of 2005.....................................................................................................1 Energy Independence and Security Act of 2007....................................................................2 Board Actions ........................................................................................................................2 2. Net Metering.........................................................................................................................3 Considerations........................................................................................................................3 Determination ........................................................................................................................4 3. Fuel Diversity .......................................................................................................................5 Considerations........................................................................................................................5 Determination ........................................................................................................................6 4. Fossil Fuel Efficiency ...........................................................................................................7 Considerations........................................................................................................................7 Determination ........................................................................................................................7 5. Smart Metering ....................................................................................................................8 Considerations........................................................................................................................8 Determination ......................................................................................................................10 6. Interconnection ..................................................................................................................11 Considerations......................................................................................................................11 Determination ......................................................................................................................11

BENTON REA—FEDERAL PURPA STANDARDS i

BENTON REA—FEDERAL PURPA STANDARDS ii

7. Integrated Resource Plans ................................................................................................13 Considerations......................................................................................................................13 Determination ......................................................................................................................13 8. Rate Design to Promote Energy Efficiency .....................................................................15 Considerations......................................................................................................................15 Determination ......................................................................................................................18 9. Smart Grid Technology Investments ...............................................................................19 Considerations......................................................................................................................19 Determination ......................................................................................................................21 10. Smart Grid Information....................................................................................................22 Considerations......................................................................................................................22 Determination ......................................................................................................................22 11. Recovery, Use and Prevention of Industrial Waste Energy...........................................23 Considerations......................................................................................................................23 Determination ......................................................................................................................24 12. Summary.............................................................................................................................25

1 Introduction

Federal legislation passed in 2005, 2007, and 2009 amend the Public Utility Regulatory Policies Act of 1978 (PURPA) to further promote renewable energy and resource efficiency. The purpose of Title 1 (“Retail Regulatory Policies for Electric Utilities”) of PURPA was to encourage conservation of energy supplied by electric utilities, optimal efficiency of electric utility facilities and resources, and equitable rates for electric customers.

The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 require that electric utilities with more than 500,000 MWh of annual retail sales consider and make a determination of several standards and policies. Each policy is meant to reduce America’s dependence on foreign energy sources, increase efficiency of energy use, equitable rates for electricity consumers, and address global climate change.

At the time of the enactment, Benton Rural Electric Association (“Benton REA”) did not meet the minimum sales requirements; however, their electric load has grown. Therefore, Benton REA retained EES Consulting, Inc. to analyze each policy as it relates to the utility. This report addresses each of the following items as required by the two acts mentioned above.

Energy Policy Act of 2005

The Energy Policy Act of 2005 was passed in the summer of 2005 in response to rising energy prices and growing dependence on foreign energy sources. The act added five new standards for state commissions and utilities to consider and determine if these policies should be implemented. These standards are listed below.

Net Metering - utility shall make net metering service available to customers per request. Fuel Diversity - utilities shall develop a plan to limit dependence on one fuel source. Fossil Fuel Generation Efficiency- utilities shall develop 10 year plans to increase the

efficiency of utility-owned, fossil fuel-fired resources. Smart Metering - utilities must conduct an investigation and issue a decision as to whether or

not smart meters should be installed for all customers. Interconnection - utilities shall make interconnection service available to electric customers

upon request. Benton REA has up to three years from the calendar year in which it exceeded the 500,000 MWh retail sales threshold to consider and make a determination regarding these policies. Benton REA exceeded the threshold in 2007 when total retail loads were 519,034 MWh.

BENTON REA—FEDERAL PURPA STANDARDS 1


Energy Independence and Security Act of 2007

In December 2007, the President signed into law the Energy Independence and Security Act of 2007. This statute added four new federal standards to PURPA section 111(d) for state commissions and utilities to consider. These standards are listed below. Integrated Resource Planning - requires utilities to consider integrated resource planning and

to integrate energy efficiency into utility plans. Rate Design to Promote Energy Efficiency - utility consideration of rate design modifications

which promote energy efficiency investments. Smart Grid Technology Investment - utilities are to consider smart grid investments in regard

to total cost, cost-effectiveness, improved reliability, security, system performance, and societal benefit.

Smart Grid Information – utilities shall provide electricity customers with access to information regarding pricing (both wholesale and retail), use, and sources.

Utilities have one year from either the enactment of the policy or from reaching the 500,000 MWh retail sales threshold to consider and make a determination regarding rate design and smart grid information. Utilities and commissions have up to two years to consider smart grid technology investments and integrated resource planning.

Non-PURPA Standards

In addition to the PURPA amendments, the Energy Independence and Security Act of 2007 added a detached standard. The last standard is with regard to “additional incentives for recovery, use, and prevention of industrial waste energy.” This non-PURPA standard does not include the retail sales threshold; therefore, all state commissions and their jurisdictional utilities and non regulated utilities must consider and make a final determination.

Board Actions

The Benton REA’s Board of Trustees will need to consider each standard and make a determination if these policies should be implemented. To assist the Board with the determination of the standards, this report provides a summary of each proposed standard, provides considerations for each standard and describes if the standard applies to Benton REA or if the standard is already implemented at Benton REA.

2 Net Metering

The Energy Policy Act of 2005 amended PURPA by adding that a utility shall make net metering service available to customers who request it. Net metering service is defined as the ability for a customer who produces energy to offset their energy consumption from the utility during that billing period. Energy produced by customers applies to qualifying on-site facilities. By allowing customers to offset energy consumption with on-site generation, more distributed generation may result. With more distributed generation, the utility would not be required to provide as much power as it would have otherwise.

Considerations

Net metering service is provided to customers who can generate energy on-site and thereby off-set their power supply costs. Net metering is an electricity policy for consumers who own (generally small) renewable energy facilities, such as wind, solar power or home fuel cells. In general, net metering is limited to smaller local generating facilities on the utility’s distribution system.

Under net metering, a system owner receives retail credit for at least a portion of the electricity they generate. Net metering rules vary significantly by State, as to how long you can keep your banked credits and how much the credits are worth. One method used to implement net metering is to allow the existing electricity meter spinning backwards, effectively banking excess electricity production for future credit. Some utilities allow market rate net metering. In this case, the user's energy use is priced dynamically according to some function of wholesale electric prices. Net metering applies such variable pricing to excess power produced by a qualifying systems. Other utilities use the net purchase and sale methodology. Under this arrangement, two uni-directional meters are installed—one records electricity drawn from the grid, and the other records excess electricity generated and fed back into the grid. The user pays retail rate for the electricity they use, and the power provider purchases their excess generation at its avoided cost (wholesale rate). There may be a significant difference between the retail rate the user pays and the power provider's avoided cost.

The implementation of net metering requires analysis of how to set appropriate rates to avoid costs shift from the net metered customer to other customers on the system. A primary concern when considering whether or not to make net metering available is ensuring that the rate paid to the customer for excess energy is a fair and equitable rate.

State Legislation

Washington State has adopted legislation that applies to Benton REA regarding net metering from renewable energy. The legislation places limits on the total capacity of net metering



generation on the system based on utility load as well as for each customer. Washington law allows the utility to decide cost allocation between utility and customer for any additional metering and equipment required for net metering. Washington Public Policy dictates that the costs incurred by the utility from interconnection and net metering are to be covered by the customer-generator rather than the entire customer base.

Washington law is written so that excess customer-produced energy will be credited to the utility on April 30th of each calendar year without compensation. The credit relieves the utility of any obligation to pay the customer for energy, and so the utility does not allocate additional costs toward the entire customer base.

Determination

Benton REA has established a policy that is consistent with both Washington State and federal standards. Benton REA General Policy 421.0 allows for interconnection of qualifying facilities fueled by renewable energy and provides net metering to its members. Net metering policies state that the utility will credit owners of qualifying facilities at a rate equal to the applicable retail rate but that excess generation at the end of the each year (April 1st) shall be donated to the utility without compensation to the member. It has been determined that the Benton REA policy meets the requirements of both the Energy Policy Act of 2005 and Washington State code.

3 Fuel Diversity

The Energy Policy Act of 2005 requires that utilities develop a plan to limit dependence on one fuel source. This section of the act is meant to encourage diversification of fuel and technology as well as the development of renewable sources. This policy is closely tied to efficiency improvements, renewable energy options, and increased reliability. Fuel diversity may be dictated by state laws and, in particular, is influenced by renewable portfolio standards (RPS).

Considerations

Fuel diversity considerations include analysis of current and foreseeable generation portfolios. As stated above, Benton REA is currently a full requirements customer of BPA. BPA’s main resource is hydropower, but BPA’s resource portfolio includes other generation technologies such as coal, biomass, natural gas, petroleum and wind through market purchases. BPA also purchases the entire output of the Columbia Generating Station, a 1,100 MW nuclear power plant.

As a full requirements customer of BPA, Benton REA is able to provide reliable electric service to its members. BPA’s current fuel diversity allows for regional reliability. In addition to reliability, the large share of hydropower on BPA’s system results in positive environmental impacts with respect to emissions of green house gases. In 2007, fossil fuel-fired resources made up less than 10 percent of BPA’s fuel mix. Commonly, BPA’s fuel mix includes over 80 percent of energy from hydropower resources.

A 2000 law directs electric utilities in Washington to report their fuel mix to customers annually or semi-annually depending upon the size of the utility. Benton REA files a fuel mix report annually to the State of Washington to meet this requirement. The following table provides the information filed by Benton REA in 2008 for the 2007 operating data.



Table 1 Benton Rural Electric Association

2007 Fuel Mix

Resource Share of Fuel Biomass 0.09% Coal 2.56% Cogeneration 0.00% Geothermal 0.00% Hydro 85.60% Landfill Gases 0.00% Natural Gas 1.06% Nuclear 10.49% Other 0.00% Petroleum 0.03% Solar 0.00% Waste 0.08% Wind 0.08%

Total 100.00%

Washington State also requires utilities with 25,000 or more customers to meet RPS beginning in 2012 with increasing standards. Benton REA is not currently required to meet RPS requirements, but would need to do so as their customer base grows.

Determination

Benton REA does not currently own the majority of resources that provide energy to its members.1 Based on the fuel mix of its contract with BPA, Benton REA has limited dependability on thermal resources. At this time, BPA resources are adequate in meeting Benton REA power requirements and no further action is required. As loads increase and new resources are needed, Benton REA will reassess the fuel diversity of its resources. It has been determined that Benton REA has adequately considered the requirements of both the Energy Policy Act of 2005 and Washington State code.

1 Benton REA members may choose to financially support the Coffin Butte project (landfill gas project shared between Benton REA and other cooperatives) through the utility’s green power program.

4 Fossil Fuel Efficiency

The third standard for consideration in the Energy Policy Act of 2005 requires that utilities develop 10 year plans to increase the efficiency of utility-owned, fossil fuel-fired resources. Fossil fuel efficiency refers to the amount of energy required to produce 1 kWh of electricity measured by Btu/kWh. The policy is aimed at equitable rate making, reduced future power costs, and increased resource efficiency.

Considerations

In order to consider this standard, utilities may have to explore whether or not they are in a position to implement a policy for fossil fuel efficiency. Utilities that do not own or control generation facilities cannot implement the standard.

Determination

In the case of Benton REA, the utility does not own the fossil fuel resources that provide power to its ultimate customers. Therefore, it is not necessary for Benton REA to adopt fossil fuel efficiency standards at this time. As such it is determined that Benton REA has adequately considered the third standard for consideration in the Energy Policy Act of 2005 regarding efficiency of utility-owned fossil fueled resources.


5 Smart Metering

The fourth standard for consideration in the Energy Policy Act of 2005 requires that utilities must conduct an investigation and issue a decision as to whether or not smart meters should be installed for all customers. Under this mandate, utilities are required to consider the costs and benefits of installing time-based meters for all customers regardless of whether or not customers want to purchase power under a time-based rate schedule. Based on the Act, utilities must conduct an investigation and issue a decision as to whether or not smart meters should be installed for all customers.

Considerations

In order to determine the cost-effectiveness of smart-meters, utilities must consider offering time-based rate schedules to all customers. Smart meters that record at least hourly quantities of electricity consumption are required to implement Time-of-Use (TOU) pricing. Once time-based rate schedules have been made available, customers can elect to take service under the applicable rate schedules. Examples of time based rate schedules are listed below:

Two Period TOU Pricing – Rates are set in advance and broken into two or three time blocks corresponding to peak, intermediate and off-peak periods. Prices are highest during the peak and lowest during off-peak.

Critical Peak Pricing (CPP) – TOU Rates are in effect for approximately 95 percent of the

hours in a year. However, in the remaining 5 percent of hours of the year which correspond to extreme peak hours of each month, prices are increased substantially to signal the increased value of energy and therefore increased benefit of reducing demand during the extreme peak period.

Real Time Pricing (RTP) – Rates are set in advance based upon a forecast of hourly real-time

wholesale prices. These real-time prices may be updated as frequently as hourly to reflect the actual cost of electricity at the wholesale level in real-time.

Load Management Credit – Credits for pre-established peak load reductions that reduce a utility’s capacity obligations.

Time-based rates may be appropriate for different applications such as different customer classes within a retail utility or across different utilities. The rejection of one TOU structure does not preclude the acceptance of another TOU structure. Other considerations include metering technologies, enrollment options such as mandatory, voluntary, or default, as well as communication technologies to notify customers of current TOU rates.


Cost Benefit Analysis Under this mandate, utilities are required to consider the costs and benefits of installing time-based meters for all customers regardless of whether or not customers want to purchase power under a time-based rate schedule. With the installation of smart meters and the implementation of TOU rates, customers will experience higher rates in on-peak periods and lower rates in off-peak periods. This price signal could cause energy consumption to shift from peak to off-peak periods and, as a result, the utility could potentially reduce its power costs. Secondly, as customers reduce on-peak consumption it may be possible for utilities to defer future capacity investments in the transmission and distribution systems. Both of these benefits need to be accounted for in the benefit-cost analysis. Additional benefits to consider include increased reliability and environmental benefits from reduced consumption.

Implementing TOU rates increases expenditures due to the need to replace or upgrade the existing metering and billing infrastructure. These costs will vary depending on the TOU program selected by the utility and the current capability of these systems.

Based on previous studies, the installation of smart meters without the application of TOU rates is not cost effective given current power costs. The installation of smart meters represents a significant cost to the utility and its customers. Assuming the utility could avoid all existing meter reading expenses, the avoided cost of implementing smart meters without implementing TOU rates is estimated to be less than the cost of the meters. Since meter installation costs are significantly greater than the avoided costs, installing smart meters for all customers was not recommended in previous studies. The root of the problem with TOU pricing in the Pacific Northwest is that current wholesale power rates from BPA are relatively flat and, therefore, do not provide a significant price signal to customers. The current diurnal and monthly rate structure does not provide price signals such that TOU and smart metering are cost effective. BPA is currently in the process of changing its rate design for rates that begin in October 2011 which will collect 85% to 95% of the total bill in a flat monthly charge. This flat monthly charge will actually diminish any price signal and as such will further discourage any implementation of TOU for the foreseeable future. Benton REA will reevaluate smart metering and TOU rates once the flat customer charge has been eliminated. Pacific Northwest Pilot Programs

During the energy crisis in 2001, Puget Sound Energy an investor owned utility in Washington State, enrolled almost 300,000 customers in a mandatory TOU rate program. Approximately 95% of its customers actually incurred higher bills under this program. While the program did result in a reduction in loads, the consumer was not able to realize a net benefit as a result of modifying its behavior. Utility staff concluded that during periods with volatile markets and soaring prices, such as occurred in 2001, TOU rates make sense. However, during periods with stable markets more study would be required to determine if a sustainable program could be designed.



In 1996, Puget Sound Energy embarked on a Real Time Pricing program for its large industrial customers. Early on there was disagreement on the appropriate price index. The program suffered greatly during the high and volatile market prices in 2000 and 2001. Ultimately, 12 customers filed complaints with the Washington Utilities and Transportation Commission and the program was terminated in 2001.

Similarly, Seattle City Light offered a variable rate for its large customers (10 MW or more) in 1996. About 50 percent of eligible customers enrolled. However, by 1998 all of these customers had opted out of the program.

In the late 1980’s Snohomish PUD No. 1 of Washington State performed a pilot TOU rate study for 120 Residential customers. While the customers were able to reduce their consumption during the on-peak period and reduce their overall consumption, the utility concluded that it was not a significant enough change for the utility to develop and implement a TOU rate structure for its residential customers.

Lewis County Public Utility District No. 1 (Lewis PUD) has had in place for the previous 15 years a time differentiated demand charge in its Primary Power customers’ rate schedule. This rate offers a reduced demand charge during the off-peak period and a flat energy rate. Over the 15 year period, none of Lewis PUD’s Primary Power customers have been able to shift their peak demand from the peak period to the off-peak period.

Determination

Previous attempts by other utilities to implement smart metering and TOU rates in the Pacific Northwest have not resulted in measurable success. In many cases, customers were not able to significantly reduce their energy bills. The lack of efficacy of these programs stem from relatively low power rates and small differences in time-based wholesale market power costs in the Northwest. Other utilities in the Pacific Northwest with power costs similar to Benton REA have studied the implementation of smart metering in detail. Given existing power and meter technology costs, smart meter implementation has not been shown to be cost effective at this time. Benton REA does not currently perceive significant benefits of smart meters and TOU rates, and given the rate structure of Bonneville Power Administration which will collect 85% to 95% of the total bill through a flat customer charge it is unlikely that Benton REA could successfully implement smart metering and TOU rates any time soon. After having completed this analysis of TOU and smart metering it has been determined that Benton REA has adequately considered the fourth standard set forth for consideration in the Energy Policy Act of 2005.

6 Interconnection

The final standard for consideration in the Energy Policy Act of 2005 requires that utilities make interconnection service available to electric customers upon request. Electric customers with on-site generation capabilities may be connected to local distribution facilities according to the specs and safety standards as defined by the Institute of Electrical and Electronics Engineers: IEEE Standard 1547.

Considerations

Benefits from the interconnection of small local resources include interconnection as a hedge against transmission and distribution investment or upgrade costs, reduced line losses, deferred investments, improved reliability, ancillary services, contingency reserves, and black start capabilities. Customers may benefit from reduced energy costs, clean energy, reduced price volatility, and increased power quality and reliability.

Interconnection costs may include additional labor costs for providing the service. Changes in load shape may result given different types of interconnected resources.

State Legislation

Currently, Washington State has implemented legislation that is meant to comply with the Energy Policy Act of 2005 as described above and to promote clean, reliable energy. Under Washington net metering rules, public utilities may offer interconnection standards for facilities up to 100 kW. Capacity is limited to one quarter of one percent of the utility’s 1996 peak demand may come from distributed, customer-owned generation through 2013. Capacity is available on a first come first served basis and limits increase to one half of one percent of 1996 peak demand beginning in 2014.

Determination

Benton REA General Policy no. 420.0 states that Benton REA shall interconnect with cogenerators and small power producers identified as qualifying facilities. The utility will purchase energy and capacities offered by the facilities, or provide wheeling service within Benton REA service territory. Compensation for these activities is determined by avoided cost.

In addition to the above policy, Benton REA General Policy No. 421.0 states that Benton REA shall interconnect with renewable energy facilities with nameplate capacities of 100 kW or less under the terms and conditions of the policy. Policy 421.0 is intended to be consistent with the requirements of chapter 80.60 RCW, Net Metering of Electricity, and to comply with the Energy



Policy Act of 2005. This policy requires safety and technical specifications under standards such IEEE 1547.

It has been determined that the Benton REA policies noted above meet the requirements of both PURPA and the Washington State legislation.

7 Integrated Resource Plans

The Energy Independence and Security Act of 2007 requires utilities to consider integrated resource planning and to integrate energy efficiency into utility, state, and regional plans. In addition, utilities should adopt policies establishing energy efficiency as a priority resource. Integrated resource planning involves evaluating different resource portfolios to meet future demand.

Considerations

Issues to consider include resource availability, cost, risk, federal, state, and local goals and legislation. Commonly, in integrated resource planning processes, both supply and demand side resources are considered to meet forecast load requirements.

The Energy Policy Act emphasizes the inclusion of cost-effective energy efficiency resources such as deployable technologies that reduce consumption without altering behaviors. Utilities often offer rebates, low interest loans, or other incentives for customers to adopt energy efficient technologies. Other energy efficiency resources can be accomplished on the utility side by upgrading transmission and distribution systems that reduce line losses.

State Legislation

The Washington State House Bill 1010 requires utilities, depending on their number of total customers, to biennially conduct either integrated resource plans or resource plans. As a utility with fewer than 25,000 customers Benton REA is required to complete a resource plan to meet Washington State mandates. The resource plan must prioritize energy efficiency and renewable resources or explain why those resources were not chosen.

Determination

As a small full requirements customer of Bonneville Power Administration, Benton REA complied with Washington’s House Bill 1010 by submitting resource planning documents in September 2008. Benton REA is the part owner of a landfill generation plant in Oregon. The plant is qualified as a renewable energy source according to the Department of Energy as well as under the Energy Policy Act. Benton REA also offers renewable energy classes for customers interested in exploring residential renewable energy projects. The class includes information about various solar and wind projects, net metering and interconnection, qualifying incentives, and cost analysis.



In addition, Benton REA has adopted the position to acquire energy efficiency resources to meet the goals set as part of its contractual obligations with BPA. Benton REA currently offers several rebates to promote energy efficiency in all sectors. It has been determined that the Benton REA policies noted above meet the requirements of both PURPA and the Washington State legislation. As Benton REA pursues future resource additions, a more detailed integrated resource plan may be needed. However, at this time, it is not necessary for Benton REA to adopt the Integrated Resource Plan standard.

8 Rate Design to Promote Energy Efficiency

The Energy Independence and Security Act of 2007 amends PURPA by adding a new standard requiring utility consideration of rate design modifications. Rate design modifications are intended to promote energy efficiency investments.

Considerations

Considerations for rate modification include the following:

Removal of any regulatory and management disincentives to energy efficiency; Provide management incentives for successful energy efficiency programs; Include the impact on the adoption of energy efficiency as a goal of retail rate design

recognizing that energy efficiency must be balanced with other objectives; Adopt rate design that encourages energy efficiency investments for each customer class; Allow timely recovery of energy efficiency related costs; Offer home energy audits, demand response programs, publicize financial and environmental

benefits of home energy efficiency improvements, educate homeowners regarding state and federal incentives, and make low-cost loans available.

Description of Each Rate Modification

Remove Disincentives

Removing disincentives includes removing declining block rates. In the past, utilities have offered electricity to customers at rate schedules that have decreasing per unit costs as the customer purchases more electricity. This rate design encourages energy use rather than encouraging energy conservation and energy efficiency. Rates that increase on a per unit basis as more energy is purchased encourage energy efficiency investments (inverted block or inclining tier block). Higher avoided costs for electricity promote energy efficient investments. Additional rate schedules that encourage energy efficiency investments are time of use rates (TOU). Time-based rates encourage customers to shift their consumption from on-peak to off-peak times, and the rates also create higher avoided costs during peak hours.

Management Incentives

Incentives in the past have linked kWh sales and revenue to management compensation. Since more kWh sales increases earnings, this compensation program provides a significant disincentive for energy efficiency. Alternatively, incentives that promote energy efficiency would link management compensation to successful energy efficiency programs.



Balancing Objectives

The third consideration is with respect to the balance between energy efficiency goals and other retail rate objectives. Other objectives may include service reliability, public safety, reasonable and just rates, economical and fair regulation. In the case of Washington State, cost-effective energy efficiency has become a priority resource. As a priority resource, rates might be adjusted to reflect that customer classes respond differently to programs and incentives. Specifically, increased retail rates may be required in order to counteract the decrease in revenue from energy efficiency programs. Since utilities must meet their revenue requirement, rates may need to increase. In addition, direct program costs may increase retail rates in the short term. The effect of energy efficiency programs on retail rates depends on how much of the revenue requirement is met by fixed monthly charges.

Timely Cost Recovery

As mentioned above, direct costs of energy efficiency programs will need to be recovered through retail rates. Utilities that are not able to recover these costs in a timely manner will likely choose not to participate. This statute mainly applies to state and other regulators of utilities.

Demand-Side Management Programs

The last subpart of the act lists several types of demand-side management programs such as energy audits, demand response, rebates, and low-cost loans. Utilities that offer these services grant customers the ability to control their energy use and, in return, control their bills.

More on Cost Recovery

The National Plan for Energy Efficiency2 describes three ways for states to recover energy efficiency program costs. The first is the direct cost recovery which allows utilities to recover the direct costs of the programs (incentives and implementation costs). Three methods for direct cost recovery are through a rate case, system benefits charge, or a tariff rider or surcharge. The second method is to recover fixed costs through a lost revenue adjustment mechanism, or decoupling of utility sales from revenue. Decoupling provides recovery of lost revenue through the separation of revenue from sales. With this second method, management incentives are removed from kWh sales. Among the states, decoupling is more popular for investor-owned utilities than lost revenue adjustments.

Lastly, the third method is utility performance incentives. Not only are energy efficiency program disincentives removed, but also financial incentives are provided to management. Incentives may be geared toward cost minimization for demand-side resource achievement. Types of incentives include performance target incentives that increase as more savings are

2 National Action Plan for Energy Efficiency (2007). Aligning Utility Incentives with Investment in Energy Efficiency. Prepared by Val R. Jensen, ICF International. http://www.epa.gov/cleanenergy/documents/incentives.pdf

achieved; shared savings incentives between the utility and customers; and rate of return adders that allow the utility to capitalize expenditures by allowing a rate of return.

Benton REA Rate Design

Utilities have a variety of rate design alternatives at their disposal. Good customer service would dictate that more pricing alternatives be provided to customers for their power supply. Use of any particular alternative has its advantages and disadvantages.

Flat Rates Block Rates Time of Use Rates

Flat rates are the most basic and commonly used type in the electric utility industry. This basic rate design is composed of two parts, a customer component and a usage charge. Flat rates have the advantage of being simple to understand and administer. However, this rate design has difficulty reflecting the true cost of bundled service, especially given varying load characteristics and time-of-day power supply costs. This design does little to influence the power purchasing decisions of the utility’s customers, since it provides little information on how consumption patterns affect costs. Currently, the farm, residential, seasonal, and some irrigation customers pay a flat rate per kWh for all energy purchased in addition to a customer charge.

Block rates are generally of two types, declining and inverted blocks. A block rate separates a consumer’s energy usage into “blocks” and applies a different rate to each block. Block rates were developed principally to reflect the cost of power supply. If power supply was a surplus commodity, declining block rates were deemed appropriate to encourage consumption. If power supply was a scarce commodity, inverted block rates were appropriate to discourage consumption

For a declining block rate, additional usage will result in lower average and marginal rates. Declining-block rates provide incentive to consume more electricity. These schedules may be a disincentive to energy efficiency investments. This would be an appropriate rate design if the marginal cost of providing such energy was also declining or below the average embedded cost of power. Increased usage would thus drive the average cost of power down. In the 1950’s and 1960’s, this was especially true. Building larger and more efficient power plants created greater efficiency in production and thus, caused average costs to decline.

An inverted block rate is based on the same principle, except that instead of lower average and marginal rates for increased usage, the rates increase with usage. Inverted-block rates provide the exact opposite incentive as declining block rates. These rates encourage conservation of energy resources, since greater consumption levels lead to higher prices. This is an appropriate rate design when the cost of energy production is increasing with increased load. This form of rate design was especially popular in the late 1970’s and early 1980’s when the economies of scale in energy production were diminishing and conservation became a primary objective.

Benton REA’s rate schedules for Commercial General Service provide that the first 20,000 kWh are purchased at one rate while energy purchased above 20,000 kWh is purchased at a lower rate.



In addition, some of the industrial and agriculture rates change by month. These monthly rates reflect wholesale power cost changes throughout the year as well as members’ seasonal consumption patterns. The monthly energy rates may provide an incentive for customer energy efficiency investments, especially projects that reduce energy consumption in the higher cost months.

In order to implement rate design which promotes energy efficiency investments, Benton REA could transition from the flat rates to inverted block rates for the farm, residential, seasonal, and irrigation customers and, at a minimum, transition from declining block rates to flat rates for the Commercial General Service member class.

The change in rate design does potentially have a large impact on customers and the utility.

1. Load factors may change unfavorably for the utility as a result of modified rate design.

2. Some customers will have significantly higher bills.

On the other hand, there are several benefits to redesigning the rate structure, as shown below:

1. Rates reflect actual increasing costs for energy consumption.

2. Increasing customer power costs reduces the need for utility rebates or other energy efficiency program incentives.

3. Inclining block rates are less regressive in design than decreasing block rates since low demand customers are not forced to pay the higher rate for all of their energy consumption. Some customers may have lower bills.

4. Cost-effective energy efficiency resources are low cost resources available to the utility.

Determination

Based on a review of Benton REA’s rate structure, there may be opportunities for rate design changes which could encourage additional energy efficiency. Benton REA evaluates rates on an ongoing basis. As the BPA power supply costs change, Benton REA will re-evaluate whether or not this change will need to be translated into the retail rate structure. However, it is unlikely that Benton REA will adopt a retail rate similar to that of BPA where 85% to 95% of the costs are collected in a flat monthly customer charge. In addition, given the current economic recession Benton REA has determined that it will not make any significant changes to its retail rate structure that could produce cost shifts between customer classes. When the economy improves and the recession is over Benton REA will again revisit this matter. The remaining rate modifications listed in the standard do not apply to Benton REA as Benton REA already provides the demand side management services to customers, and no management disincentives exist. Therefore, it is not necessary for Benton REA to adopt this standard at this time and it does not intend to do so.

9 Smart Grid Technology Investments

State regulatory authorities and non-regulated entities are to consider smart grid investments in regard to total cost, cost-effectiveness, improved reliability, security, system performance, and societal benefit. Smart grid investments are to be considered before traditional transmission projects are implemented.

The Energy Independence and Security Act of 2007 mainly relies on states to set standards regarding cost recovery for smart grid investments as well as obsolete technology reimbursements. However, utilities are still required to consider smart grid investments and to make a determination. The purpose of the act is to modernize the electricity grid. Below are smart grid technologies as listed by Section 1301 of the act:

Increased use of digital information and control technology improves reliability, security, and efficiency of the grid.

Dynamic optimization of grid operations and resources, with full cyber-security. Deployment and integration of distributed resources and generation, including renewable

resources. Development and incorporation of demand response, demand-side resources, and energy

efficiency resources. Deployment of ‘‘smart’’ technologies (real-time, automated, interactive technologies that

optimize the physical operation of appliances and consumer devices) for metering, communications concerning grid operations and status, and distribution automation.

Integration of ‘‘smart’’ appliances and consumer devices. Deployment and integration of advanced electricity storage and peak-shaving technologies,

including plug-in electric and hybrid electric vehicles, and thermal-storage air conditioning. Provision to consumers of timely information and control options. Development of standards for communication and interoperability of appliances and

equipment connected to the electric grid, including the infrastructure serving the grid. Identification and lowering of unreasonable or unnecessary barriers to adoption of smart grid

technologies, practices, and services.

Considerations

Deployment of smart grid technologies will likely occur over time. Advanced meter infrastructure (AMI) smart appliances, thermostats, distributed generation, and local storage are some of the smart grid technologies that have shown peak demand reduction by up to 40 percent. Before adopting any of the above technologies, utilities should first find out if there is a distribution cost cap preventing cost recovery. If there is none, then the next step is to analyze net benefits of each technology and how the costs will be allocated. The allocation of cost re-introduces the issue of rate design and lost revenue issue again. Specifically, utilities may be



able to take advantage of one or more cost recovery mechanisms provided by the state or regulating entity. Cost recovery mechanisms include trackers that follow costs over a year, balanced accounts that recover costs not covered through retail bills, decoupling, customer surcharges, and state funding. Due to the nature of smart grid technologies, utilities might implement technologies in stages. For instance, smart appliances have been found to be cost effective but they are not commercially available at this time. GE has partnered with Louisville Gas & Electric (LG&E) to initiate a new line of smart appliances that use wireless technology and energy conservation meters to help consumers save electricity.3 These appliances are paired up with smart electric meters that communicate with the appliance. GE plans to spend nearly $1 billion on marketing and development of smart appliances in the next 3 to 5 years. When these appliances become available, they are expected to cost consumers 5 to 10 percent more than standard GE appliances.

Smart Grid Technologies

Before making a determination for each smart grid technology, information on what technologies are available is needed. Below is a list of currently available products as well as some upcoming technologies.4

GFA Controllers: Small electronic circuit board that detects when the electricity grid becomes stressed and in response regulates the power schedule of appliances such as water heaters. These devices were used in the Grid Friendly Appliance Project on the Olympic Peninsula, Washington.

Tendril Networks: Tendril’s suite of in-home display options and web portal are examples of intelligent devices and applications that may transform the electric power industry. Tendril Networks’ Insight provides homeowners with a visual tally of how much electricity they are paying for at each moment. In four months in 2008, Tendril signed 9 of their total 29 contracts with utilities to test and/or deploy its technology.

GridPoint: Another example of the types of products and services (operations center, control consol, customer portal and customer support) that use two-way communication capabilities.

Greenbox: Emphasis on transparent in-home display of energy consumption information. Electricity use and pricing information is made available to end-users.

Positive Energy: Uses a combination of technology, analytic direct marketing, and behavioral science to inform consumers about their energy use. Positive Energy has developed a hosted software application that generates quarterly or monthly reports for consumers on how their

3 Adams, Brent. “GE to launch new appliance line, team up with LG&E for energy conservation program.” Business First, Wednesday September 24, 2008.

4 Technology list is from Lynne Kiesling’s Blog, Knowledge Problem. “Intelligent end-use devices make a transactive smart grid valuable (Part 3 of 5). March 4, 2009. The permanent link is located here: <http://knowledgeproblem.com/2009/03/04/intelligent-end-use-devices-make-a-transactive-smart-grid-valuable-part-3-of-5/>

http://www.tendrilinc.com/

http://www.gridpoint.com/

http://www.getgreenbox.com/

http://www.positiveenergyusa.com/


energy use compares to people in the same area. Smart meters are not required to use the software application.

EnergyHub: In-home energy use monitor and hardware that shows consumers how their home uses energy.

Ecobee: A programmable thermostat geared toward transparent display of energy consumption information, focused on heating and cooling. Ecobee uses existing home wireless network for its communication capability.

Current Cost (UK): Another home energy monitor device and software. Also, individual appliance monitors will be available soon.

WattzOn: An energy use tracking web site, not a device. Customers enter information about the various devices in their homes and the site recommends behavioral changes. While this technology is not exactly two-way communication, it may help consumers adjust their energy use.

Google Power Meter: Up and coming software technology that monitors energy use by time of day, electricity price, and appliance.

Many of the above technologies require smart meters; however, WattzOn, Ecobee, and a few others do not require advanced meter technology.

Determination

The Recovery Act increases Federal incentives for smart grid technologies for use in demonstration projects from 20 percent of applicable project costs to 50 percent. Also the specific dollar amount allocated to smart grid technologies is removed so as to imply no cap or minimum federal expenditure. These incentives are available as grants. As the technology becomes more developed and Benton REA determines that they are cost effective, these smart grid investments will be considered in conjunction with traditional investments on an ongoing basis to ensure the most cost effective option is selected. Therefore, it is not necessary for Benton REA to adopt this standard at this time, and it does not intend to do so.

http://www.energyhub.net/Home.html

http://www.ecobee.com/

http://www.currentcost.com/

http://wattzon.com/

http://www.google.org/powermeter/

10 Smart Grid Information

Standard (17) in section 1307 of the Energy Independence and Security Act requires that states consider providing electricity customers with access to information regarding pricing (both wholesale and retail), use, and sources. This information may be provided in written or electronic form and be provided no less than daily. States and non-regulated utilities have up to one year after enactment to make a determination regarding smart grid information.

Considerations

Utilities considering adopting an information standard would need to consider the following: Medium of information exchange

• Written form • Web-based

Frequency of communication and projection • Daily, hourly • Day-ahead price projections

Information regarding electricity sources may be provided annually. Electricity source information will include type of generation and greenhouse gas emissions.

Determination

At this time, Benton REA’s cost of power supply depends on Bonneville Power Administration rates. These rates are fixed monthly rates for on-peak and off-peak periods and can be found on Bonneville Power Administration’s website. In addition, Benton REA already reports the fuel mix annually to the State of Washington. Therefore, it is not necessary for Benton REA to adopt Smart Grid information policy at this time, and it does not intend to do so.


11 Recovery, Use and Prevention of Industrial Waste Energy

The last requirement for utilities under the Energy Independence and Security Act is to consider incentives for industrial waste energy recovery. Waste energy includes exhaust heat or flared gas and waste gas. The standard is separated into six parts described below:

1. Consideration of Standard. Establishes a time limit for state commissions and nonregulated utilities to begin consideration and make a determination.

2. Standard for Sales of Excess Power. Contains the standard’s general language that is to be considered by state commissions and nonregulated utilities.

3. Options. Contains four options for the treatment of net excess power from a project owner or operator of an eligible waste energy recovery project.

4. Rate Conditions and Criteria. Contains definitions and rate conditions for the sale and transport of power from eligible waste energy recovery projects.

5. Procedural Requirements for Consideration and Determination. Sets the requirements for public notice and hearing, intervention by the Environmental Protection Agency Administrator, and the procedures for consideration and determination of the standard by states and nonregulated utilities.

6. Implementation. Contains a general implementation requirement for state commissions and nonregulated utilities to implement or decline to implement the standard and additional requirements if the standard is declined.

Considerations

Within 6 months of receiving a request from a project sponsor, owner, or operator, the utility must provide public notice and conduct a hearing on the standard and consequently make a determination. If the standard is declined, a project sponsor may submit a new project petition at any time two years after the date the utility declined to implement the standard.

Separate consideration and determinations are needed for each project unless projects are consolidated. Projects are approved on a case by case basis with no grandfathering measures.

Possible alternatives for the sale of power from eligible waste energy recovery projects include sales to the utility, transport by utility for sale to a third party, transport via private transmission lines, or some other agreed upon alternative between the owner operator and the utility.



Rates and costs are defined in the following three parts:

1. Per unit distribution cost - depreciated book value of the distribution system divided by utility sales.

2. Per distribution margin – per unit gross pretax profit for regulated utilities, or rate of return on distribution assets times per unit distribution costs.

3. Per unit transmission costs – total cost of transmission services purchased or provided by the utility per kWh included in retail rate.

These rate conditions should be considered; the above conditions may be incompatible or inconsistent with current regulatory practices. For instance, distribution and non distribution costs for utilities may not be separated. Also, the criteria above are expressed as system averages; however, rate making processes may result in rate design for a customer class that is not representative of the average system.

Determination

No additional determination is required at this time. Each case is considered individually as they are brought to the utility by an owner operator. Once an owner operator presents a case, Benton REA will consider the project and make a determination at that time.

12 Summary

In order to meet the requirements of the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, Benton REA has considered and made determinations regarding several policies. A summary of these determinations is provided below.

Net Metering – Benton REA has established a policy that is consistent with both state and federal net metering standards. General Policy 421.0 allows for interconnection of qualifying facilities fueled by renewable energy and provides net metering to its members.

Fuel Diversity – Benton REA does not currently own the majority of resources that provide energy to its members. Based on the fuel mix of its contract with BPA, Benton REA has limited dependence on thermal resources. At this time, BPA resources are adequate in meeting Benton REA power requirements and no further action is required. As loads increase and new resources are needed, Benton REA will reassess the fuel diversity of its resources.

Fossil Fuel Generation Efficiency – Benton REA, does not own the fossil fuel resources that provide power to its ultimate customers. Therefore, at this time Benton REA is not able to adopt fossil fuel efficiency standards.

Smart Metering – Previous attempts to implement smart metering and TOU rates in the Pacific Northwest have not resulted in significant success. Because BPA wholesale power rates in 2011 will include a flat monthly customer charge that is expected to collect 85% to 95% of the total monthly charges, Benton REA does not perceive significant benefits of smart meters and TOU rates. As power supply costs change, or if BPA changes their billing determinants to send price signals, then the utility will reconsider TOU and smart meter standards.

Interconnection – Benton REA General Policy No. 420.0 states that Benton REA shall interconnect with cogenerators and small power producers identified as qualifying facilities. In addition General Policy No. 421.0 states that Benton REA shall interconnect with renewable energy facilities with nameplate capacity of 100 kW or less under the terms and conditions of the policy.

Integrated Resource Planning – As a small customer of Bonneville Power Administration, Benton REA complied with Washington’s House Bill 1010 by submitting resource planning documents in September 2008. In addition, Benton REA is part owner of a landfill generation plant, offers renewable energy classes for customers, and has adopted the position to acquire energy efficiency resources to meet the goals set as part of its contractual obligations with BPA. The Benton REA policies noted above meet the requirements of both PURPA and the Washington State legislation. As Benton REA pursues future resource additions, a more detailed integrated resource plan may be needed. However, at this time, it



has been determined that it is not necessary for Benton REA to adopt the Integrated Resource Plan standard.

Rate Design to Promote Energy Efficiency – Based on a review of Benton REA’s rate structure, there may be opportunities for rate design changes which could encourage additional energy efficiency. However given the current economic recession Benton REA has determined that it will not make any significant changes to its retail rate structure that could produce cost shifts between customer classes. When the economy improves Benton REA will again revisit this matter. As the BPA power supply costs change, Benton REA will re-evaluate its retail rate structure, but it is unlikely that it will adopt a retail rate structure like BPA’s where 85% to 95% of the costs are collected in a flat monthly charge.

Smart Grid Technology Investment – The Recovery Act increases Federal incentives for smart grid technologies. As the technology becomes more developed and Benton REA determines that they are cost effective, these smart grid investments will be considered in conjunction with traditional transmission investments on an ongoing basis to ensure the most cost effective option is selected. Therefore, it has been determined that it is not necessary for Benton REA to adopt this standard at this time.

Smart Grid Information – At this time, Benton REA’s cost of power supply depends on Bonneville Power Administration rates. These rates are fixed monthly rates for on-peak and off-peak periods and can be found on Bonneville Power Administration’s website. In addition, Benton REA already reports the fuel mix annually to the State of Washington. Therefore, it has been determined that it is not necessary for Benton REA to adopt Smart Grid information policy at this time.

Recovery, Use and Prevention of Industrial Waste Energy – Each case is considered individually as they are brought to the utility by an owner operator. Once an owner operator presents a case, Benton REA will consider the project and make a determination at that time.

Documents

Benton REA Report