Fair Transmission & Distribution Rules

From Powerful Solutions: Seven Ways to Switch America to Renewable Electricity, UCS, 1999

Some have argued that a revolution in the way we make and move electricity is developing. New generation technologies-like fuel cells, photovoltaics, wind turbines and natural gas microturbines-are available in small modular units that can be sited in, on, and around buildings where power is used. Many "distributed" technologies also create waste heat that can be easily used on the spot for water and space heating, boosting their efficiency. These distributed technologies already offer an economical alternative to building large central station power plants and new power grids in remote areas that do not have transmission and distribution (T&D) systems. As the prices of the new technologies fall, they may completely reshape existing power networks as well. As discussed in Chapter 1, distributed generation technologies can provide substantial non-traditional benefits to utilities and their customers.

Recognition of the added value that distributed technologies can provide can be critical for new technologies entering the market. UCS's 1995 Renewing Our Neighborhoods study looked at the Boston Edison service territory and compared the cost of upgrading the aging transmission and distribution system in certain neighborhoods with the cost of installing renewable technologies. Even though renewables tend to be higher priced than central station power, UCS found that some renewable technologies may already be cost-effective in areas where particularly expensive transmission and distribution investments can be avoided. Studies in other parts of the country have found similar results.In a study of potential early markets for solar photovoltaics, the Utility Photovoltaic Group found that the potential US market for photovoltaics at a cost of $3 per watt is as high as 7,630 MW for distributed power applications, compared with 1,130 MW for the potential "green market" at this price. [3] Of course, photovoltaics is not likely to capture most or all of the potential distributed market. It must compete with other distributed technologies which can provide "distribution services." These include distributed electricity storage, such as batteries, and demand-side management technologies, such as energy efficiency investments, which can reduce demand in targeted regions or neighborhoods, extending the usefulness of existing distribution equipment.

Because many renewable energy technologies operate intermittently when the sun is shining or the wind blowing, there are added difficulties in valuing their output fairly. Traditionally, the reliability value of an electricity generator is based on the maximum output that can be turned on, or "dispatched," by the system operator, especially during periods of peak electricity demand. Because individual renewable generators may not be dispatched at will, and cannot be guaranteed to be available during peak times, they have frequently been assumed to have zero reliability value.

There is often, however, a relatively consistent relationship between the output of an intermittent renewable and the level of electricity demand over time. Solar output, for example, tends to be high on mid-afternoon on hot sunny days, which is often when air conditioning use is also high. Utilities have long used statistical methods to allocate costs to classes of customers based on a tendency to use electricity more during high-cost vs. low-cost periods. Similar methods can be used to allocate benefits to intermittent generators based on a tendency to produce electricity during high-value or low-value periods.

Few utilities have closely examined the reliability value of intermittent renewables for their systems. Fewer still have looked at the potential value of renewables in reducing peak demand on their distribution systems. Because the mix of customers and the times they use electricity may vary greatly from one neighborhood to another, the value of intermittent technologies in deferring or avoiding transmission or distribution expenditures may vary greatly from location to location.

In order to realize distributed technology benefits, however, electricity distribution companies must value distributed technologies fairly and be willing to invest in them or encourage their customers to invest in them when they can reduce system costs. Traditional cost-plus regulation has not necessarily encouraged least-cost distribution planning. Also, because methods to value distributed generation in planning distribution systems are new, few utilities have yet adopted them. Utilities are beginning to show greater interest in distributed resources, however. [4]

A restructured industry presents new opportunities and barriers for distributed generation.[5] A more competitive industry is likely lead to specific identification of cost centers and profit opportunities. Location-based transmission or distribution rates, which would be higher where there is congestion, could lead to generation being sited in areas where it has greater value. Independent companies that could profit from providing distributed generation services would have a strong incentive to seek out potential opportunities.

On the other hand, the separation of vertically-integrated utilities into separate functional units or separate companies providing generation, transmission, distribution, and retail marketing services may make it harder to identify the integrated value a distributed technology provides in each of these areas. It is uncertain which market players will have the resources and incentives to make the investments to avoid a combination of generation, transmission, and distribution costs faced by other market players. A transition to location-based distribution pricing, where separate distribution prices would be charged to different neighborhoods based on local costs, would raise significant equity issues. Residents in a neighborhood with aging distribution facilities (who shared the cost, under regulation, of upgrading distribution facilities in other neighborhoods) may well resent seeing distribution price increases designed to induce local distributed generation.

And just as some utilities have avoided investing in new power plants that risked making existing power plants economically obsolete, some companies may resist distributed technologies that could compete with their existing transmission and distribution investments. In many cases, therefore, legislators or regulators may need to establish appropriate rules and incentives.

Many states that have shown some interest in these issues have been preoccupied with overall industry restructuring. There is therefore little experience to draw on at this time.

Connecticut and Massachusetts have addressed distributed technology issues in their restructuring processes. Connecticut's restructuring law requires "demand-side management" expenditures to be considered as alternatives to distribution expenditures. Demand-side management generally refers to technologies to reduce electricity demand, like energy efficiency investments, or to methods that shift demand from one period to another. Distributed generation technologies installed in customer buildings also reduce the system demand for electricity, however, and could be included in regulations developed to implement the Connecticut law.

In Massachusetts, the Department of Telecommunications and Energy has stated that distributed generation will be considered as part of performance-based ratemaking proceedings. This policy, as an alternative to cost-of-service regulation, seeks to induce utilities to reduce costs and improve performance by linking incentives to specific performance measures.>

Performance-based ratemaking in Massachusetts and elsewhere has generally been implemented with a price cap. Under a price cap per kilowatt hour, distribution companies have an incentive to sell more kilowatt hours to increase total revenues. Price caps provide disincentives to reduce sales through distributed generation or energy efficiency investments. In contrast, under a revenue cap, total company revenues are fixed, and a company does not lose revenues from distributed technology investments. Prices are adjusted periodically to make up for any unanticipated revenue shortfalls or surpluses. Therefore, a company does not lose revenues or profits if it encourages reduced electricity demand through energy efficiency or distributed generation. Oregon has adopted a revenue cap. [6]>

In California, environmental organizations and renewables companies have petitioned the Public Utilities Commission to establish distributed generation regulations. As of November 1998, however, no formal action on the petition had been taken.

One way of ensuring appropriate investment in distributed technologies would be to require regulatory review of transmission and distribution planning decisions. Such planning reviews would be analogous to "Integrated Resource Planning" (IRP) for generation, extended to the distribution planning level. Investments in the distribution system would be reviewed to ensure they have invested in the mix of demand-side and supply side options that provide electricity at the lowest cost.) While there has been a trend to reduce IRP regulatory review in favor of increasing competition in generation, it may be appropriate to retain it for regulated transmission and distribution companies.

Distribution IRP would be somewhat more complex than generation IRP. Generally, however, companies will be planning major transmission or distribution investments in only a few areas at any given time, thus limiting the complexity of the review. One potential model for distribution-level IRP has been developed for the Boston Edison Demand-Side Management Settlement Board. [7]

One way to insert distributed generation into the planning process would be to require distribution companies to competitive bids for distribution services where new investment is required. Distributed technology providers could then compete against traditional equipment upgrades. Another approach would be for the system owner to offer incentives for distributed generation in specific parts of the system that are weak or overtaxed.

One important issue likely to affect utility activities in distributed technology is whether they can own distributed generation. [8] Distribution company ownership of these technologies raises antitrust and anticompetitive concerns. There has been some concern that allowing utility ownership could undermine the development of distributed generation by seeking to be monopoly providers of distributed generation technologies. On the other hand, allowing ownership of distributed generation provides them with an incentive to become active in this area. Massachusetts has explicitly allowed distribution companies to own distributed generation.

Transmission Rules

Renewable energy generators' unique characteristics pose challenges to designing fair transmission rules and prices. Renewables generators must be located where the natural resources are, and sometimes must be transmitted long distances. The intermittent output and low capacity factor of some renewables creates operational issues for the transmission grid (i.e., having backup capacity if the wind suddenly stops blowing) and pricing issues similar to those covered above with distributed generation.

In 1996, the Federal Energy Regulatory Commission (FERC) Order 888 required utilities to make transmission available to all generators and customers. [9] FERC has also encouraged the formation of Independent System Operators (ISOs), groups of multiple stakeholders to control the operation of the transmission network. These developments should increase renewables generators' access to customers. It should also reduce multiple transmission charges, known as "pancaking," when power is transmitted across more than one utility system and each utility exacts a toll.

Transmission service is typically specified as firm or nonfirm, with nonfirm service more interruptible in cases of transmission constraints. FERC did not specify how transmission prices should be set, but proposed that all firm transmission service be based on reservations of transmission capacity made at least one day in advance. Generators would pay for reserved transmission whether or not they used it. They would be subject to penalties if they exceeded or fell short of their reservation by more than 1.5 percent. [10]>

This requirement would heavily penalize intermittent generators like wind and solar, where it is hard to predict output accurately a day in advance. If it turns out to be windier than predicted, and not enough transmission capacity is reserved, the wind generator could be unable to sell all the electricity generated. If it were less windy than expected, the generator would be stuck paying for unused transmission. Ideally, generators would be able to resell reserved transmission capacity that they could not use, but this secondary market has not really developed. Renewables generators would have to resell transmission capacity at the last minute, making it unlikely they would get a good price, and transaction costs would be high. Renewables generators could, however, bundle their output together with power sources that can be turned on and off as needed, such as gas turbines. But requiring such bundling would reduce generator and marketer flexibility and might raise total costs. [11]

Generators could also buy non-firm transmission service without a reservation. However, buyers of non-firm service can have their transmission interrupted if the lines get congested. And lenders may charge higher financing costs if renewables generators do not have firm transmission contracts. [12]>

The formation of ISOs, with multiple stakeholders, has created pressure for more flexibility and options in transmission service, which may benefit renewables. ISOs that include power exchanges-spot markets for electricity sales-plan to charge spot market prices for transmission that is higher or lower than scheduled amounts, for example. California is currently operating in this manner.>

However, as of the end of 1998, most ISOs are still in the process of formation, with their makeup, governance, rules and pricing still under development. The ISOs in formation generally do not include power exchanges. >[13]

Some early ISO proposals have some negative implications for renewables. A Southwest proposal would require generators who want nonfirm transmission service to have backup reserve capacity. A New England ISO proposal would impose "nonusage" charges for both firm and non-firm transmission services. [14]

Another transmission issue affecting renewables is the pricing of "ancillary services" needed to maintain system reliability, such as reserve generating capacity to compensate for plant outages. The wind industry has supported continued cost-based regulation of these services by FERC, although some analysts suggest that market-pricing may provide more flexible services for renewables. [15]

Some ISOs have proposed "postage stamp" rates-one price for transmitting power from anywhere within a region to any other point within the region. Others have proposed "megawatt mile" charges that vary with distance. Congestion charge proposals also vary. The impact of these proposals will vary with specific renewables projects. Generally, transmission costs do not increase linearly with distance, so loading all transmission charges onto a megawatt mile may not treat remote projects fairly. Having many small "postal zones" could have a similar or worse effect, however.

>An analysis by the Lawrence Berkeley Laboratory (LBL) shows charging for unused transmission capacity can raise the cost of the entire electricity system. LBL developed a two-tier pricing system, which bases transmission access charges on energy transmitted and congestion charges on capacity reservations. The access charges would be used to cover fixed costs-80 to 90 percent of network costs. LBL shows that this pricing scheme would lead to a least-cost technology mix, as well as reducing the penalty for intermittent renewables, without creating a special condition for them. [16]

1. See EPRI, PG&E, and NREL. An Introduction to the Distributed Utility Valuation Project, Monograph, 1993; Coles, R.L., et al. Analysis of PV benefit Case Studies: Results and Method Used, NREL Draft Report, May 1995.
2. Union of Concerned Scientists, 1995. Renewing Our Neighborhoods: Opportunities for Distributed Renewable Energy Technologies in the Boston Edison Service Territory, August., 1995.
3. Opportunities in Photovoltaic Commercialization: Report of the UPVG's Phase I Efforts, Part 4, Commercialization Strategies Work Group, Utility Photovoltaic Group, Washington, DC, June 1994, p. 38.
4. See, for example, Taylor Moore, "Emerging Markets for Distributed Resources," EPRI Journal, March/April 1998, cover story, p. 8.
5. For a thorough treatment of distributed generation legal and regulatory issues, see John Nimmons, Thomas Starrs, Ren Orans, Joel Swisher and Joel Singer, Legal, Regulatory & Institutional Issues Facing Distributed Resources Development, Prepared for the National Renewable Energy Laboratory, Central & Southwest Services, Inc., Cinergy Corp., Florida Power Corp., San Diego Gas & Electric, National Renewable Energy Laboratory NREL/SR-460-21791.
6. Oregon Public Utilities Commission, PacifiCorp-Distribution Only AFOR, Order No. 98-191, May 5, 1998. Available online at www.puc.state.or.us/orders/98orders/98-191.pdf.
7. Henry Yoshimura, Robert Graham, and Christopher Hebert, La Capra Associates, An Incentive Regulatory Framework to Encourage Cost-effective Investment In Transmission and Distribution System Resources in a Restructured Electric Utility Industry in Massachusetts, Boston Edison Demand-Side Management Settlement Board, September 28, 1995. Summary and order information available online at www.magnet.state.ma.us/doer/utility/orderreg.htm.
8. Nimmons et. al., ibid.
9. Federal Energy Regulatory Commission, Open Access Rule, Order 888, April 27, 1996. Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities (RM95-8-000).
10. Federal Energy Regulatory Commission, Capacity Reservation Open Access Transmission Tariffs, Notice of Proposed Rulemaking, FERC Docket No. RM96-11-000, April 24, 1996.
11. For more detail about the effects of transmission issues on renewables, see Kevin Porter, National Renewable Energy Laboratory, "What is Happening with Independent System Operators?" Presented to Windpower '98, American Wind Energy Association, Bakersfield, Calif., April 30, 1998, available online at www.nrel.gov/analysis/emaa/isos.pdf; Steven Stoft, Carrie Webber, and Ryan Wiser, Transmission Pricing and Renewables: Issues, Options and Recommendations, Lawrence Berkeley National Lab, Berkeley, Calif., May 1997, available online at eetd.lbl.gov/EA/EMP/emppubs.html; Kevin Porter, "Open Access Transmission and Renewable Energy Technologies." National Renewable Energy Laboratory Topical Issues Brief NREL/SP-460-21427. September 1996 Available online at www.nrel.gov/analysis/emaa/open_access/index.html; Steven Stoft, Carrie Webber, and Ryan Wiser, Transmission Pricing and Renewables: Issues, Options and Recommendations, Lawrence Berkeley National Lab, Berkeley, Calif., May 1997, available online at http://eetd.lbl.gov/EA/EMP/emppubs.html.
12. Stoft et. al., ibid.
13. Porter, Windpower '98, ibid.
14. Porter, Windpower '98., ibid.
15. Porter, Windpower '98, ibid
16. Stoft et al, ibid.