ADDENDUM TO THE
When the Draft Fourth Northwest Conservation and Electric Power Plan (draft power plan) was released in March 1996, the region had just embarked on an effort to develop consensus on how the electricity industry of the Northwest should be restructured to accommodate increasing competition. That effort, the Comprehensive Review of the Northwest Energy System, was convened by the governors of Idaho, Montana, Oregon and Washington. The governors appointed a steering committee to conduct the review and charged them to "develop, through a public process, recommendations for changes in the institutional structure of the region’s electric utility industry. These changes should be designed to protect the region’s natural resources and distribute equitably the costs and benefits of a more competitive marketplace, while at the same time assuring the region of an adequate, efficient, economical and reliable power system."
To support this process, the draft power plan was intended as a reference tool on the changes in the industry. Public comment on the draft power plan was left open for a year with the goal of revising the plan when the conclusions of the Comprehensive Review, as well as other public comment, could be taken into account.
This addendum, in combination with the original draft power plan, accomplishes that goal. The two taken together constitute a revised Draft Fourth Northwest Power Plan. The Council will accept public comment on the revised draft until October 31, 1997. Public hearings will be held in each of the states during September and October. The final plan is scheduled for adoption in December 1997.
This addendum has two principal objectives. First, it reviews important developments since the release of the draft power plan. These developments include what has happened with respect to: generation and conservation resources, gas and electricity markets, electricity loads, institutions, and policies. While there have been significant developments in the electricity industry since March 1996, none of them invalidates the analysis contained in the draft power plan. The more important developments include the creation of new institutions in response to the increasingly competitive utility industry, and the continued evolution of policies at the state and federal levels designed to facilitate competitive electricity markets.
The second purpose of the addendum is to examine the relationships between the analysis contained in the draft power plan and the recommendations from the Comprehensive Review’s Steering Committee. In several instances, this addendum suggests approaches that would help move the Northwest from the usually general nature of the Steering Committee’s recommendations to the specifics that will have to be addressed by legislatures and state and local regulators.
The draft power plan focused primarily on issues raised by the transition to competitive electricity markets and highlighted, where possible, important considerations and principles in that transition. The Comprehensive Review dealt with many of the same issues. In general, the recommendations from the Review are supported by the analysis of the draft power plan or, where they are not, the recommendations reflect legitimate policy choices on the part of the Review’s Steering Committee. In many instances, however, the recommendations from the Review are specific in intent but, of necessity, lacking in detail. For example, one recommendation is that provisions for recovering stranded investments be made as part of opening retail electricity markets to competition. However, the recommendation provides little guidance regarding how stranded investment recovery might be structured and why. This addendum builds on the analysis in the draft power plan to suggest important considerations in recovering stranded investments. The same is true with respect to several of the recommendations for competition and consumer access, and provisions for conservation and renewable resources.
This addendum also describes potential new roles for the Northwest Power Planning Council that are based on recommendations from the Comprehensive Review. After the conclusion of the Comprehensive Review, the governors of Idaho, Montana, Oregon and Washington created the Northwest Energy Review Transition Board to oversee implementation of the Steering Committee’s recommendations. The Transition Board is made up of the four governors’ representatives that served on the Steering Committee: Northwest Power Planning Council Chair John Etchart of Montana, Council Member Todd Maddock of Idaho, Council Member Mike Kreidler of Washington and Roy Hemmingway of Oregon. Council staff are supporting the work of the Transition Board. During the transition to a more competitive electricity market, the Council has been asked to help the region ensure that the benefits of competition are shared by all electricity consumers, and that public purposes, such as energy-efficiency improvements, development of renewable resources and services to low-income customers, continue to be provided.
The Fourth Northwest Power Plan explores key issues this region must address as the electricity industry becomes more competitive. As noted above, many of these issues are being reckoned with by the Northwest Energy Review Transition Board. For example, the Transition Board has created a public process, including work groups, to address two significant questions: how can the Bonneville Power Administration survive competition when its power rates are at or above market prices; and how can the region maintain an efficient and reliable transmission system. Both of these efforts are aimed at securing for this region the future benefits of the federal power system while encouraging open and equitable competition in the utility industry. Because the work groups have not concluded their efforts, this power plan does not offer recommendations for how these questions could be answered. The Council is closely engaged in the work group efforts both through the Transition Board, on which three Council members serve, and through staff analysis and support for the work groups.
Most of the other issues relate to the region’s ability to facilitate
effective competition in electricity markets while sustaining the commitment to
improving efficiency of electricity use, encouraging renewable resources and
providing electricity services to low-income customers. Utilities and their
regulators are working to promote competition, protect consumers, maintain
reliability, improve efficiency and develop renewable resources at the same time
that the entire industry is being restructured. The analysis presented in the
draft power plan and the recommendations from the Comprehensive Review point out
some important directions the region can take to ensure an effective and
equitable competitive retail electricity market and maintain the Northwest’s
commitment to conservation, renewable resources and low-income energy services.
Nonetheless, these directions frequently mean dramatic changes for the
institutions involved, and they are not without their tensions and, in some
instances, contradictions. The analysis in the draft plan and the
recommendations from the Comprehensive Review are described in this addendum. In
many instances, however, the Comprehensive Review Steering Committee’s
recommendations are, of necessity, general in nature. They provide little detail
or guidance on how to address the challenges and conflicts inherent in
implementing many of those recommendations. In this section, the Council
summarizes its own recommendations for addressing the problems of implementing
the recommendations of the Comprehensive Review. The Council’s recommendations
are intended for state and local policy-makers.
The Comprehensive Review Steering Committee noted that effective separation of utilities’ distribution and energy marketing functions is necessary if a truly competitive retail market is to be established. The alternative is the potential for self-dealing and preferential treatment of the incumbent utilities’ energy marketing activities.
The Comprehensive Review Steering Committee recommended that the unbundling of electricity prices and recovery of transition costs (e.g., stranded investment recovery and public purpose funding) be carried out in a competitively neutral fashion.
The Comprehensive Review Steering Committee noted that information about the market is critical if the market is to be both fair and efficient. The Steering Committee made specific recommendations regarding information to be provided on customer bills.
The Comprehensive Review Steering Committee recommendations include a number of new public responsibilities — provision of consumer information services, monitoring and enforcing competitive conditions, development and evaluation of pilot programs, ensuring reasonably consistent market conditions and consumer protection laws and their enforcement, registration and licensing of energy service providers, development of a consumer complaint and arbitration process, and creating and administering a universal service fund.
If these functions are to be carried out, responsibility needs to be assigned and the activities supported. Provision should be made for many of these services to be funded through a competitively neutral distribution system charge, as has been proposed for other public purposes.
Utilities with higher-cost resources could experience stranded investment during the transition to competition — fixed costs that cannot be recovered at market prices. Conversely, utilities with low-cost supplies could experience "windfall profits" from being able to charge market prices. The Steering Committee noted that an opportunity for recovery of stranded investments from the historical customer base is an appropriate transition mechanism.
The Comprehensive Review Steering Committee recommended that local utilities be responsible for collecting and using most of the public purpose funding for conservation and low-income weatherization.
The Comprehensive Review Steering Committee recommended that public purpose funding for renewable resource development be administered by a regional non-profit entity, but gave local utilities the right to choose to use those funds for their own renewable resource development.
The energy marketing staff at local utilities frequently have the knowledge and expertise for renewable resource development, but in a competitive environment, they may be averse to the risk that the public purpose funding will not be sufficient to cover the above-market costs of renewable resources, potentially creating stranded investments.
The Comprehensive Review Steering Committee expressed a preference for relying on market forces wherever possible to achieve the region’s goals for developing conservation and renewable resources. This implies that, to the greatest extent possible, the restructuring of the electricity industry should be done in ways that complement or encourage the development of competitive markets for energy-efficiency services and renewable resources.
The Comprehensive Review Steering Committee recommended that the investments in energy efficiency by "large consumers" should be credited against the public purpose funding requirements for local conservation. If the intent is to foster a market for energy-efficiency services, then this crediting of consumer investment should be interpreted as liberally as possible, consistent with being able to ensure that legitimate efficiency investments are actually made. In that way, utilities will be encouraged to foster the marketing of energy-efficiency services to consumers, as opposed to simply making utility purchases of conservation.
As open access occurs, it will be important that all qualified entities have the opportunity to compete for the use of the public purpose funding for conservation and renewables. This will promote a competitive market for these services.
Using the public purpose renewable resource development funding in the form of a consumer-directed credit against the cost of power purchases from qualified renewable resource producers is a market-oriented approach to encouraging renewable resource development.
The recommendations of the Comprehensive Review Steering Committee appear to focus on ensuring that funds are collected to sustain development of conservation and renewables. They do not provide much guidance on how the money should be directed, other than in very broad categories.
The recommendations of the Comprehensive Review Steering Committee generally give preference to local implementation of conservation and renewable resources. There are, however, several areas where regional activities are recommended and others where regional coordination of local activities would be desirable.
The Steering Committee recommended establishment of a "regional technical forum" to track progress on conservation and renewables, and provide feedback for improving effectiveness of these efforts. This is an important function to ensure accountability. To accomplish these functions, this body will have to be given adequate support and authority by the states and/or local utilities.
The Steering Committee recommended that regional conservation and renewable resource goals should be reviewed at least every five years, taking into account changes in market conditions. Provisions should be made in state legislation and/or local regulations to permit adjustments to regional goals, and the function of reviewing these goals, should be given adequate support and authority.
The Steering Committee recommended that conservation market transformation be undertaken through a regional non-profit entity. Such an entity, the Northwest Energy Efficiency Alliance, has been established with voluntary funding from Bonneville and investor-owned utilities. That funding is not assured beyond 1999. State legislation establishing public purpose funding should ensure continued funding. In addition, the makeup of the board of directors should be revised to reflect the public nature of the funding.
The Steering Committee recommended that renewable resource development intended to transform the market for renewable resources be administered by a regional non-profit, but gave "first right of refusal" to local utilities. The limited amount of available funding and the characteristics of the most promising renewable resources suggest that regional coordination of such development is required if there is to be any substantial effect. State legislation establishing public purpose funding for renewable resources should require regional coordination and adequate support for that function.
The Northwest Energy Efficiency Alliance was not constituted to address renewable resource issues. Either its mission and makeup should be altered or a different entity should be charged with this responsibility.
The Steering Committee recommended that public purpose funds for distributed generation research, development and demonstration be administered by a regional entity. However, the localized nature of distributed generation opportunities requires a coordinated regional/local approach. The kinds of technologies eligible for this funding should be identified by the regional entity. Specific projects should be designed and implemented locally. State legislation establishing public purpose funding for distributed generation research, development and demonstration should require regional administration, local implementation and stable financial support for these efforts.
A review of recent trends in electricity demand and its major determinants shows that both the economic and energy use forecasts included in the draft power plan remain appropriate as a basis for the final plan. In the time since the draft power plan was published, the regional and national economy have experienced continued healthy growth. Aggregate employment and population remain close to the forecast levels in the draft. Non-manufacturing employment, which accounts for about 85 percent of the total, was just 0.6 percent above the medium forecast for 1996. Manufacturing employment has grown more rapidly than the forecast, primarily as a result of strong cyclical growth in the aerospace and electronics industries.
The other major determinants of electricity demand are fuel and electricity prices. Fuel prices, and especially natural gas prices, are an important assumption, not only for demand forecasting, but also for determining electricity generation costs and analyzing competitive pressures. In general, oil prices have been lower than the draft power plan forecasts, while natural gas prices have been higher. However, both prices are highly cyclical, and there is no indication that the expected long-term trends embodied in the draft power plan have changed. An updated comparison of the Council’s forecasts of natural gas prices with those of other organizations shows that most organizations’ gas price forecasts have been reduced since the draft power plan was developed. When the draft power plan was published, the Council’s forecast range was lower than most other forecasts (see page C-7, Figure C-5, in Volume II of the draft power plan). However, an updated comparison in Figure 1 shows that the same organizations’ forecasts are now tending to fall into the middle and lower portion of the Council’s forecast range.
Figure 1. Natural Gas Price Forecast Compared to Council Forecasts
(Council Forecasts Range = Solid Lines)
AGA: American Gas Association AGA-TERA Base Case, August 1996.
CEC: California Energy Commission "Staff’s Preliminary Forecast of
Natural Gas Production and Wellhead Prices," April 9, 1997.
DRI: Data Resources Incorporated/McGraw-Hill, World Energy Services: U.S.
Outlook, Spring/Summer 1996.
EIA: Energy Information Administration, AEO (Annual Energy Outlook) 1997,
December 1996.
GRI: Gas Research Institute "GRI Baseline Projection of U.S. Energy Supply
and Demand," 1997.
WEFA: WEFA Group, U.S. Energy Report, Spring/Summer 1996).
In the draft power plan, electricity price forecasts were partially adjusted to account for growing competition. However, the ultimate effect of restructuring on retail electricity prices is difficult to predict at this time. Much will depend on decisions that are made about stranded investment recovery. It is likely that electricity prices will be lower in a restructured industry in the long term, but the decrease will be smaller in the Pacific Northwest where electricity prices are already low.
There is only one year of additional energy use data available since the draft power plan. It does appear, however, that actual sales are staying close to the demand forecasts. Given that there is no evidence of changes in long-term trends since the draft power plan forecasts, the forecasts will not be changed for the final plan. In any case, long-term demand forecasts and resource planning are far less important in a more competitive electricity market because consumers and power brokers will dictate resource decisions. The decisions the region is facing have more to do with ensuring effective competition and continued reliability in the electricity market and securing public benefits. These new concerns are the subject of this power plan.
The draft power plan described a study of the potential power supply available to the Northwest from California and the inland Southwest. That study indicated that utilities could expect to purchase power from a Westwide market. Power from this western market is expected to be widely available and relatively low in cost into the next decade compared to the full cost of investing in new generation. During certain peak load periods, however, power would likely become increasingly expensive on a spot basis. The study noted that reliability could also be a concern with substantial power imports using the interties between California and the Northwest.
Since the study was completed, the western power market has developed further. The Federal Energy Regulatory Commission (FERC) has published its final Orders 888, 888A and 889, which mandate open, comparable and non-discriminatory access to transmission systems and standards of conduct to ensure that utilities’ day-to-day operations support that access, as well as, the creation of an electronic trading system for transmission capacity. The New York Mercantile Exchange (NYMEX) has offered futures contracts at the California /Oregon border and at the Palo Verde substation in Arizona.
Generally, the experience of utilities receiving intermediate-term (up to five year) offers, which appear to be the bulk of the offers, from power marketers has been consistent with the perspective offered by the study. It is difficult to compare the study and real experience directly because the study included only California and the inland Southwest. The California/Oregon border and Palo Verde prices of the last two years were affected by both extreme temperatures and substantial nonfirm energy availability from the Northwest.
For instance, the current 12-month (May 1997 to April 1998) average of futures prices at the California/Oregon border is approximately 17 to 18 mills, but this includes the known effects of a high runoff forecast in the Northwest and, presumably, expected hydropower conditions during the August through May period. This price is generally consistent with the study results for a comparable calendar year, which included only the effect of average hydropower conditions in Northern California and excluded the effect of Northwest power supplies.
During the summer of 1996, there were two major power outages in the West involving the interties. These outages resulted in significant losses of load, particularly in areas that were importing power at the time, California and the inland Southwest. Similar outages during the winter, with a similar level of transfers occurring into the Northwest would have likely led to similar load losses across the Northwest. These outages drew attention to transmission reliability issues in an environment of increasing competition and with an increasing number of non-traditional actors. The Western Systems Coordinating Council (WSCC), under the auspices of its parent body, the National Electric Reliability Council (NERC), and in coordination with the western states, has embarked on an effort to define and enforce mandatory reliability standards for all participants in the western power market. The Council is monitoring these efforts.
The draft power plan (Section 4-A) noted that power plant development, which had been very active since the late 1980s, was declining. Though several hundred megawatts of new capacity were under construction, no solicitations for new power plants were issued in 1995. The draft attributed this trend to low natural gas prices (which increases the competitiveness of existing natural gas-fired capacity) and an increasingly active wholesale market resulting in more efficient use of generating capacity on the interconnected western systems.
The pace of resource development continues to decline. New generating projects capable of producing approximately 495 average megawatts were placed in service during 1996. In addition, energy-efficiency measures capable of conserving approximately 85 average megawatts of electric energy were installed in 1996. The total 1996 conservation and generation development of 580 average megawatts was down from the 715 average megawatts placed in service during 1995 (Figure 2).
Approximately 370 average megawatts of new energy-efficiency measures and generation are expected to enter service in 1997, continuing the downward trend observed in the draft power plan. Figure 2 illustrates the increased development activity of the mid-1990s, followed by the more recent decline.
Figure 2. Electric Energy Resource Development Trends
Changing technologies and industry structure have improved the industry’s ability to respond to changing market conditions. The short construction lead time of gas-fired combined-cycle power plants, greater access to wholesale price information and concerns regarding stranded investments have accelerated the current downturn compared to past instances following appearance of overcapacity. Furthermore, although the latest downturn is not completely free of stranded costs, the short-lead times, low capital cost and relatively small unit sizes of gas-fired combined-cycle power plants appear to have far less potential for creating stranded capital than was the case in earlier downturns, which involved large, capital-intensive nuclear and coal plants.
As evident in Figure 2, the role of natural gas in power generation continues to increase. Natural gas generation comprised 86 percent of generating capacity additions in 1996, compared to 65 percent of all generating capacity additions over the five-year period from 1992 through 1996. At the end of 1996, natural gas provided 7 percent of the firm electric energy potential of Northwest plants. Scheduled completions will increase this to 8 percent by the end of 1997.
Though little new construction is under way, prospective plant developers continue to seek permits for new projects in anticipation of stronger future electricity prices. While 444 megawatts of capacity are under construction, an additional inventory of 3,590 megawatts of capacity is permitted, but not under construction. Prospective developers are seeking permits for about 2,370 megawatts of capacity (Figure 3).
Figure 3. Power Plant Development Status, December 1996
The resource assessment of the draft power plan concluded that combined-cycle power plants using natural gas fuel constituted the most cost-effective new source of bulk power for the Northwest. Natural gas supplies appear to be abundant. Suitable sites appear to be available for new plants sufficient to produce more than 7,000 megawatts of energy.
The draft power plan also concluded that a diverse and reasonably large inventory of renewable resources is available for development, although most are not cost-effective at this time. Solar, wind and geothermal resources are potentially available in large quantities, and biofuels could be produced in large quantity. Forest residues are widely available, and other biomass residues suitable for fuel, including landfill gas, clean municipal solid waste and miscellaneous agricultural wastes, are available in smaller, but significant quantities. Modest amounts of energy are thought to be available from undeveloped hydropower and upgrades to existing hydropower and biofuel plants. Ocean energy potential is very small.
Nearly all new renewable resource development opportunities are more expensive — frequently several times more — than current wholesale energy prices. Moreover, most renewable resources are more expensive than power from new gas-fired combined-cycle power plants. Exceptions might include upgrades to existing hydropower and biomass power plants and specialized projects using biomass residues. Technology improvements and economies of scale are expected to continue to reduce the cost of many renewable resources. Over the past several years, however, declines in the price of natural gas and improvements to combustion turbine technology have resulted in declines in the cost of electricity from gas-fired power plants that have outpaced cost declines among renewable resources.
The conclusions of the resource assessment of the draft power plan remain generally valid. The following events, however, may affect the cost or availability of wind, geothermal and natural gas resources. Wind turbine performance and costs used in the draft were based on the Kenetech KVS-33 turbine. The technical failures of Kenetech’s KVS-33 variable-speed turbine and the subsequent bankruptcy of Kenetech Windpower suggest that these assumptions were optimistic. Unsuccessful geothermal production wells and cessation of exploration at Newberry Volcano suggest that the electric generating potential of Northwest geothermal resources may be more limited than was estimated in the draft power plan. Finally, some evidence has surfaced of continued and significant decline in combined-cycle combustion turbine power plant capital costs. The latter is being investigated by Council staff.
The draft power plan (Section 6-C) assess the potential economic risk to the power system of global climate change — potentially the most significant power system externality. The assessment examined the effects of efforts to control greenhouse gas production on power system cost, resource cost-effectiveness, the value of conservation and the value of renewable resources. Taxes on carbon emissions were used to represent the economic impact of greenhouse gas control measures.
Carbon taxes equivalent to $10 and $40 per ton of carbon dioxide emitted would increase the regional cost of providing power by an estimated 3.7 to 14.7 percent, respectively. These carbon tax levels are in the range of estimated environmental damage values attributed to climate change. Carbon taxes would increase the cost-effectiveness of conservation and renewable resources relative to new and existing fossil fuel resources, and would increase the cost-effectiveness of new gas-fired power plants relative to existing fossil fuel resources. Carbon tax levels of $10, $20 and $40 per ton would increase the discounted present value of conservation opportunities in the Northwest from an estimated $2.3 billion to $3.2, $4.6 and $6.1 billion, respectively. Potential renewable resources would increase in value from an estimated $28 million to $86, $226 and $997 million, respectively. Though insufficient information was available for a quantitative analysis, domestic and overseas greenhouse gas controls in other economic sectors, carbon sequestration and other non-power measures might prove to be more cost-effective than the power-related measures considered in this analysis.
The draft power plan offered the region the following recommendations:
Since preparation of the draft power plan, the Intergovernmental Panel on Climate Change (IGCC), an international assemblage of scientists convened by the United Nations to study the matter of global climate change, released its final 1995 report. In this report, the IGCC concluded, for the first time, that "the balance of evidence suggests that there is discernible human influence on climate."
Following the conclusions of the 1995 IGCC report, and with increasing evidence that voluntary efforts to reduce emissions of greenhouse gasses are unlikely to meet target levels, the parties to the United Nations Framework Convention on Climate Change issued a Ministerial Declaration at the Second Conference of the Parties, held in Geneva in July 1996. This declaration states that the governments present would accelerate negotiations on the text of a legally binding protocol, to be completed for adoption at the Third Session of the Conference of the Parties. The Parties recommended that that protocol include "quantified legally binding objectives for emission limitations and significant overall reductions within specified timeframes, such as 2005, 2010, 2020" of human-caused emissions of greenhouse gasses. This recommendation has been controversial, spurring a great deal of opposition. The Third Session is scheduled for December 1997, and the outcome is unclear.
An important regional development relative to greenhouse gas control is the Oregon carbon dioxide standard. Legislation that would revise the Oregon power plant permitting process has passed the legislature and has been signed by the governor. This revision includes the requirement that power plant developers offset a portion of the carbon dioxide production of new fossil-fuel plants. The law requires net carbon dioxide production be limited to 83 percent of the carbon dioxide production of a state-of-the-art combined-cycle plant fueled by natural gas. The developer is generally free to choose how the reductions in carbon dioxide production will be achieved, whether by advanced technology, sequestering, or other means, providing the approach used is verifiably effective. The estimated cost of complying with this proposal at the present time is $0.57 per ton of carbon dioxide reduction (approximately a quarter of a mill per kilowatt-hour). This figure does not represent an estimate of the potential damage attributable to climate change, which is frequently much higher, but an estimate of the current cost of achieving carbon dioxide offsets. At this level, the proposal is not expected to substantially affect resource selection. Rather, project developers will seek compliance through low-cost carbon offset measures.
Because the analysis of the draft power plan was based on examples of possible climate control measures, rather than a specific forecast of the magnitude and timing of climate control measures, the subsequent events described above do not change the findings of the plan’s analysis. However, these events do suggest that the probability of climate control measures being needed and enacted has increased somewhat. In this environment, it is important that all cost-effective conservation be secured. The climate control and renewable resource recommendations of the draft power plan also become more important, as do the recommendations regarding the preferred form of climate control measures:
As stated in the draft power plan, the Northwest, by its own actions, is unable to significantly affect global climate. However, actions such as the Oregon carbon dioxide standard and continued efforts to improve energy efficiency and develop renewable resources can signal political support for greenhouse gas control measures at the federal and international level.
There have been no major changes in policy that would alter the analysis of the 1996 draft power plan. If anything, policy developments since the release of the draft have confirmed the major thrust of the draft, namely, the movement of the electricity industry toward competition. The Federal Energy Regulatory Commission (FERC) released its Orders 888, 888A and 889, providing for open, non-discriminatory transmission access and wholesale stranded cost recovery.
Many of the states have been moving relatively quickly to open their retail electricity markets to competition. The California Legislature passed legislation that fundamentally enacts the recommendations of the California Public Utilities Commission calling for opening of retail access by 1998. The California legislation also provided for stranded investment recovery and support of conservation and renewable resources through a "transition charge." California is well on its way to establishing the power exchange (pool) called for by its Public Utilities Commission, as well as an independent system operator. Pennsylvania, New Hampshire and Rhode Island have also passed legislation opening their retail markets, and legislation is pending in many other states. In the Northwest, legislation opening retail competition in Montana was signed into law early in 1997. Oregon and Washington legislatures both worked on legislation in 1997, but did not pass bills. Washington, Oregon and Idaho all have interim activities planned to look at restructuring legislation. As of late spring 1997, the regulatory commissions of nine states have issued final restructuring orders for their investor-owned utilities, and 11 states have retail access pilot programs or experiments under way. The foregoing does not include whatever actions individual consumer-owned utilities may have taken on their own.
At the national level, several pieces of legislation have been introduced to hasten the move to retail competition. They range from legislation that would preempt state authority by requiring open access in the states by a certain date and stipulate at least some of the conditions to legislation that leaves most decisions to the states. While it is considered unlikely that federal legislation on retail competition can be passed this year, many observers expect action in the next two to three years.
There has also been legislation introduced to privatize the federal power marketing agencies. While there appears to be little weight given to this legislation, it is apparent that the role of the federal power agencies will be under scrutiny as the utility industry restructuring efforts at the federal level proceed.
Within the region, there has been considerable institutional evolution as the electricity industry moves toward competition. Some of the more important actions include efforts to form an independent grid operator, the formation of the Northwest Energy Efficiency Alliance and the continuing trend of mergers and strategic alliances in the industry.
The effort to form an independent grid operator, called IndeGO, began with the Northwest investor-owned utilities. IndeGO’s participants have subsequently expanded to include the major transmission owners in the West outside of California, Arizona and New Mexico. The Bonneville Power Administration, the Northwest’s federal power marketer, will require legislation to allow it to turn federal facilities over to a non-federal entity for operation if it is to be a member of IndeGO. However, Bonneville has been participating fully in the formation efforts. The formation of IndeGO was given additional impetus last summer by major power outages on the western system. These events underscored the stress that the existing management of transmission was experiencing under the demands of competition and the need to develop new institutions better suited to the new industry environment.
Under IndeGO, scheduling of all transmission would be turned over to the grid operator. Pricing of transmission services would also be governed by IndeGO, subject to regulation by the Federal Energy Regulatory Commission. As of this writing, IndeGO appears headed toward a pricing policy in which most of the cost of transmission would be recovered in access fees. This policy is based on the assumption that most of the costs of transmission were committed in the past and are not dependent on the amount of electricity being transmitted. That is, the cost of transmitting the marginal kilowatt-hour is essentially zero. Congested transmission paths would be treated differently to create an economic incentive for relieving congestion. This kind of pricing eliminates the "pancaking" of transmission charges that characterized transmission across several different transmission systems. The policy would mark a significant improvement in terms of economic efficiency.
For the independent grid operator concept to work, the operator must be truly independent. IndeGO directors will be independent of all parties significantly affected by IndeGO. Indeed, in public meetings, IndeGO representatives have proposed that IndeGO organizational documents have explicit provisions barring election of directors with ties to organizations that could have conflicts of interest. The independent directors would be elected by a plurality of the membership in IndeGO from different classes. If IndeGO follows the membership classes established by the Northwest Regional Transmission Association, it would include: 1) transmitting utilities; 2) transmission-dependent utilities; 3) non-utility entities, which are energy marketers (but not brokers or retail customers); and 4) commissions, which are state and provincial utility regulatory commissions, state energy commissions, and regional, state or provincial agencies with rate-making, siting, or resource-planning authority in regard to electrical energy. As of this writing, the plan is to not allow the commission class to elect directors, but to give them the power to reject directors that are elected by the other three classes.
IndeGO is aiming for a submittal to FERC by September of 1997 that proposes IndeGO take responsibility for transmission scheduling in July 1999 and responsibility for system security in July 2000.
The draft power plan highlighted some of the difficulties facing the development of conservation in a competitive environment. One promising avenue appears to be market transformation, which aims to increase the long-term market for efficiency products and services through targeted efforts with manufacturers, retailers and others. An example of market transformation is the Northwest’s Manufactured Housing Acquisition Program. Under this program, significant payments were made to manufacturers for producing factory-built homes that meet high levels of energy efficiency. The utility payments resulted in lower purchase prices for consumers, so far more of the energy-efficient homes were sold. The payments were subsequently phased out, and only minor marketing assistance continued. Market penetration has fallen, but has continued at a much higher level than the pre-program level.
Because most markets cut across utility service territories, successful market transformation typically requires cooperation on at least a regional scale. Over the past year, the Northwest Energy Efficiency Alliance was formed as a non-profit corporation with roughly proportional funding from Bonneville customers and the region’s six investor-owned utilities. The funding amounts to approximately $13 million in 1997 and $26 million in 1998 and 1999. The Alliance has a board of directors with six representatives from Bonneville and the public utilities, six from the investor-owned utilities and six from the states, public interest and efficiency industry groups. The regulatory commissions are ex-officio members. The Alliance has taken over funding and management of several market transformation efforts that were in the formative stages (e.g., efficient clothes washers) and has initiated efforts to identify and develop additional market transformation opportunities. Funding after 1999 is uncertain. The Comprehensive Review recommended that $30 million per year be allocated to this effort regionally. This is dependent on implementation of the recommended funding levels for conservation in state utility industry restructuring legislation and the allocation of that funding to the Alliance or some other regional body for market transformation efforts.
An expected response to the prospect of competition is the growing trend for utilities and others in the industry to seek cost-reduction opportunities and/or market advantages through strategic alliances and mergers. Two mergers have dominated regional attention. One has been the merger of Puget Sound Power and Light and Washington Natural Gas to form Puget Sound Energy. This merger, promises greater efficiency through consolidation, and the strategic advantage of positioning the new company as a major supplier of both gas and electricity.
More intriguing is the acquisition of Portland General Corporation, the parent company of Portland General Electric, by Enron Corporation, the natural gas pipeline and marketing company. This merger would not appear to offer a lot in the way of consolidating functions. Enron, however, is working to position itself as a national marketer of electricity at the wholesale and retail levels. The acquisition of Portland General will give the company first-hand experience in the retail electricity market, as well as a strategic location within the West Coast electricity market.
While not as dramatic, there are also numerous strategic alliances forming. These range from an alliance between Puget Sound Energy and Duke Power, to smaller-scale alliances that include utilities such as Washington Water Power, Chelan Public Utility District and Tacoma Public Utilities. These alliances are intended to take advantage of unique skills or resources that each partner brings to the alliance.
The most important question for regional power planners and consumers is what effect these activities will have on the electricity market. If the effect is the intended reduced costs and improved products and services, the mergers will be welcomed. If, however, the effect is the ability of some market participants to exert market power, there could be cause for concern.
The Comprehensive Review Steering Committee recommended that the governors of the Northwest states name a "Northwest Energy Review Transition Board" to oversee implementation of a number of the Committee’s recommendations, focusing particularly on those affecting Bonneville, such as subscription sales of federal power and Bonneville’s competitive role. The governors appointed their representatives from the Steering Committee to serve as the Transition Board. Three of the four Transition Board members are Power Planning Council members, and the Council also provides staff support for the Board. The governors also asked the Transition Board to keep the Northwest congressional delegation informed on these issues.
Two implementation work groups broadly representative of the interests in the region have been formed to work toward implementation of the Steering Committee’s recommendations for Bonneville. The first, on federal power subscriptions, was formed by Bonneville and the Pacific Northwest Utilities Conference Committee, which represents Bonneville’s customers. This work group reports regularly to the Transition Board. The second, on separation of Bonneville’s transmission and generation functions, was formed by the Transition Board. Both work groups are actively working through the details of how to implement these recommendations. Because federal power marketing and transmission issues are being addressed in public processes through the work groups, this addendum does not provide the additional analysis that it provides on the recommendations regarding customer choice, conservation and renewable resources.
The Council’s draft power plan raised several key issues about the future role of the Bonneville Power Administration in a competitive market. These issues were divided into three main areas: 1) the consistency of various aspects of Bonneville’s status as a federal power marketer with a competitive market, including separation of transmission and generation, market power, and risk and reward trade-offs; 2) the allocation of the benefits of the federal hydropower system; and 3) future support for the various public purposes that Bonneville historically supported.
The draft power plan discussed some key characteristics of competitive markets and suggested that Bonneville, because it controlled large portions of both the region’s transmission and generation capability, has the potential to exercise too much control over the power market. That would be inconsistent with open and fair competition. Furthermore, as a federal agency, Bonneville is limited in its ability to deal with the risks and rewards that are essential aspects of a competitive market.
The draft power plan discussed several alternative approaches to the separation of Bonneville’s generation and transmission functions. The plan also examined different approaches to the disposition of federal power marketing rights that would better balance risk and reward, and be more consistent with a competitive power market.
The draft power plan also examined the allocation of historic and expected future regional benefits of the federal hydropower system operated by Bonneville, including future mechanisms that would retain those benefits for the region while being more consistent with a competitive market and the risk and reward balancing that it implies.
Finally, the draft power plan suggested that several of the public purposes that Bonneville had historically supported, such as funding energy-efficiency programs and renewable resources, and special rates for certain classes of customers, could be inconsistent with a competitive power market and would be unlikely to be the kinds of things that Bonneville would be able to support in the future.
The Comprehensive Review Steering Committee also concluded that the issues identified in the draft plan were critical and addressed them in its deliberations. The Steering Committee’s conclusions on separation of transmission and generation are reviewed in the following section of this addendum. The Steering Committee recommended that Bonneville’s role in a competitive market, particularly its potential market power, be limited by selling Bonneville’s power, to the extent possible, under longer-term subscriptions. The recommendations also called for a more limited Bonneville role in resource acquisition. These limitations would tend to minimize the political exposure of Bonneville as a government-owned supplier in a competitive market. The recommendations also limited the market risk that Bonneville could take on, given that, as a federal agency, it lacks risk-taking owners, the means by which typical participants in competitive markets deal with risk and absorb losses.
The Review’s final report summarized this issue as follows:
The recommendations would have the effect of disposing of much if not all of the firm power available from Bonneville on a long- or intermediate-term basis. The fact that most of Bonneville’s power would be subscribed at cost would limit Bonneville’s market role. Any remaining firm power and other power products would be sold at Federal Energy Regulatory Commission (FERC)-regulated prices or at competitive prices, where FERC determines that competitive markets exist. To the extent consistent with its obligation to repay Treasury, Bonneville should return to its historic role of marketing power generated by the Federal Columbia River Power System, rather than becoming an aggressive marketer of products and services in the emerging competitive power market.
In addition, it is recommended that Bonneville would not acquire resources to serve its customers’ load growth except on a direct bilateral basis where the customer takes on all the risk of the acquisition. Similarly, it is proposed that Bonneville would not sell directly to new retail loads, beyond the existing direct service industry loads, although it may sell through intermediaries whose transactions would be subject to state or local jurisdiction.
The related questions of balancing risk and reward and of allocating the benefits of the federal hydropower system were central to the deliberations of the Comprehensive Review. The Steering Committee summarized its goals for federal power marketing:
1) align the benefits and risks of access to existing federal power; 2) ensure repayment of the debt to the U.S. Treasury with a greater probability than currently exists while not compromising the security or tax-exempt status of Bonneville’s third-party debt; and 3) retain the long-term benefits of the system for the region. The recommendation is also intended to be consistent with emerging competitive markets and regional transmission solutions.
The Steering Committee chose a solution that favored long-term subscriptions to federal power that would be sold at cost. Cost might be somewhat higher than market prices in the near term, but is expected to be lower in later years. This scheme aimed at having the subscribers take on more of the current business risk of Bonneville, in return for an assured ability to buy electricity at below-market prices in the future. Some customers might wish to limit their exposure to Bonneville’s costs being at above-market prices by deferring making longer term commitments until the risk has been reduced by the passage of time and by the consequent better knowledge. Those wishing to make short-term purchases would have to pay a premium, in the form of an option payment, to renew the contracts at cost at a later time.
Finally, the draft power plan raised the issue of the potential inability of Bonneville, in a competitive market with relatively low market prices, to support all of the public purposes that extended beyond selling power at cost to utilities. The discussion of this problem, and of potential replacements for historic utility support, was an important part of the Steering Committee’s effort. The solution for the most prominent of these purposes, conservation, renewable resources and low-income energy assistance, goes beyond Bonneville to encompass all the electricity providers in the region and is described later in this addendum.
Bonneville and the Pacific Northwest Utilities Conference Committee have formed a subscription work group open to all regional interests to implement the federal power marketing recommendations from the Comprehensive Review. The work group reports regularly to the Transition Board.
The subscription work group has set out a multiyear work plan for implementing the Steering Committee’s recommendations and permitting the signing of new Bonneville power sales contracts in advance of the termination of current contracts. During Phase 1 of the workgroup’s effort, through mid-1998, the group is addressing business interests, product definition, pricing principles and potential legal issues. Phase 2, mid-1998 through mid-2000, is expected to be devoted to a rate case and final contract negotiations. Currently, the work group is well ahead of schedule in its Phase 1 work, having explored the business interests of potential subscribers and the definition of the products they are interested in buying from Bonneville. Alternatives for an overall contractual relationship with Bonneville and more detailed definition of products are the current focus of the work group.
The draft power plan summarized recent developments in national policy related to electricity transmission. The Notice of Proposed Rulemaking issued by the Federal Energy Regulatory Commission (FERC) in March 1995 indicated that the Commission’s implementation of the National Energy Policy Act of 1992 would require several things of utilities under its jurisdiction: 1) "unbundling" of the costs and operation of transmission from those of generation; 2) transmission tariffs that offered transmission service to other parties on the same terms as the utility applies to itself; and 3) providing timely information about availability and costs of transmission. The goal of these requirements was a transmission system that would be open to all competitors in the generation market on equal terms, and would make possible effective competition in the wholesale market for electricity.
The draft power plan described alternatives for separation of transmission and generation, and it described the alternatives’ relative effectiveness in reducing the opportunities and temptation to use control of transmission to benefit a utility’s generation business. The alternatives (listed in order of increasing certainty that effective open access to transmission will be achieved) are: 1) functional separation within the utility; 2) spinning off generation and transmission subsidiaries within an existing corporation; 3) turning over control of transmission assets to an independent operator; and 4) divestiture — selling off the generation or transmission assets to new owners. Unfortunately, the more certain alternatives are also the most complex to implement.
The Steering Committee stated that its primary goal for transmission was "a transmission system whose structure and operation help ensure a fully competitive generation market." It recommended the formation of an independent grid operator to operate the region’s transmission system, including Bonneville’s assets. It recommended that "Bonneville’s generation and transmission functions should be fully and legally separated (including separated funds)" and that the separation "be achieved in such a way that it does not jeopardize or diminish the legal obligation and ability of Bonneville to meet fish and wildlife and other obligations." The Steering Committee also recommended that Bonneville’s transmission be subject to FERC regulation "that is equivalent to FERC regulation of investor-owned utilities."
As noted earlier, the formation of an independent grid operator along the lines of the Steering Committee’s recommendations (IndeGO) was begun in July 1996, and is making progress toward filing a proposal with FERC in September 1997. The group of participants, initially seven investor-owned utilities, had grown to 21 by March 1997, including Bonneville and utilities with assets in eight states. Bonneville is participating in the group’s discussions, but Bonneville has expressed the opinion that it will not be able to turn over control of its assets until a number of issues are resolved and necessary legislation adopted.
The governors’ Transition Board formed a transmission working group to discuss how best to accomplish the separation of Bonneville generation and transmission. That workgroup has been meeting since April 1997. One of the major issues the group is examining is how to effectively separate generation and transmission without threatening the security of bonds issued by the Washington Public Power Supply System (WPPSS), and without compromising the ability of Bonneville to mitigate the effects of the power system on the region’s fish and wildlife. If the separated power marketing organization has trouble meeting its revenue requirements, should it be able to call on the separated transmission organization for financial support? Holders of WPPSS bonds, fish and wildlife advocates and the federal treasury are likely to resist a separation that appears to threaten their interests. On the other hand, prospective users of the separated transmission system and competitors of the separated power marketing organization will not be satisfied with an arrangement that leaves Bonneville with significant incentive and ability to use the transmission system to benefit its power marketing revenues.
Another of the Steering Committee’s recommendations that the working group is discussing is regulation of Bonneville’s transmission by the Federal Energy Regulatory Commission that is equivalent to its regulation of investor-owned utilities. The work group has made progress toward definition of "equivalent" regulation of Bonneville’s transmission. Next, the group intends to consider to what extent, and in what areas, it would be appropriate for FERC regulation of Bonneville to depart from "investor-owned equivalent."
The Council addressed the issue of competition and consumer choice in Chapter 3 of the draft power plan, entitled "Capturing the Benefits of Competition." That Chapter described the potential benefits of a competitive electricity market, but also discussed the risks and limitations of such markets. As the title implies, the chapter focused on the conditions necessary for effective competition and methods of pursuing non-market objectives within the context of a competitive market. It also raised some transitional issues as the region moves toward a competitive electricity market. It was clear that the Council expected transmission and distribution to remain regulated monopoly functions while electricity generation and marketing would move toward an unregulated competitive structure. Some of the key recommendations addressed the uneasy coexistence of regulated and competitive markets in providing electricity services.
An important concern in the draft power plan was to foster and protect a competitive electricity market. The critical condition necessary to have a truly competitive market is absence of market power for any of the participants in the market. The role of open market access in ensuring adequate competition was discussed. Without open non-discriminatory consumer access to electricity suppliers, and electricity suppliers’ access to consumers, consumer’s choices would be limited. Without consumer choice, there can be no competitive retail market. Since the transmission and distribution system are the means of access to the market, the draft power plan concluded that it is important that these regulated functions be carefully separated from the competitive components of the industry. If actual divestiture was not undertaken, then either additional structural and institutional changes, such as the independent grid operator, or additional regulatory attention would be required to ensure against anti-competitive behavior. In addition, different rules and regulations among market participants, including different tax treatments, can turn into competitive advantages or disadvantages and may lead to market power for some participants.
The draft power plan discussed the characteristics of competitive markets and pointed out the particular difficulties faced by federal or public agencies competing in such markets. The key problem is how difficult it is for such institutions to absorb profits and losses that are inherent in competitive markets. This poses a challenge for this region’s transition to competitive electricity markets because of the importance of the Bonneville Power Administration and its public utility customers in the regional power system.
The draft power plan acknowledged that few industries match the economist’s ideal structure for competitive markets. Important concerns for the electricity industry include environmental costs that are not reflected in market prices, inadequate information on alternatives and their costs, and average cost pricing through regulation, instead of the marginal cost pricing that characterizes competitive markets. The last issue will be addressed by the deregulation of electricity markets. Many unregulated industries have environmental consequences and do not provide sufficient consumer information. But such shortcomings may be more important in the electricity industry, especially during the transition from full regulation to a mixed competitive and regulated industry.
Providing adequate information is critical to fostering competitive markets because it allows consumers to exercise their market choices intelligently. The lack of adequate consumer information can be a barrier to efficient market operation. The importance of price and service information was discussed in the draft power plan, including the unbundled pricing of the components of electricity service.
Environmental protections, along with other social objectives such as low-income or rural support, have been addressed successfully in the past through the regulated electricity market, and the costs have been included in electricity prices. However, in a competitive market these costs cannot simply be added to the price of electricity. The draft power plan points out that transfers or subsidies cannot be sustained in a competitive electricity market unless they are equally applicable to all market participants. If these purposes are to be maintained, other mechanisms must be found.
The draft power plan identified stranded costs as a key issue to be addressed during the transitional period. There is a risk that some consumers may gain early access to other suppliers, leaving behind costs that would be borne by remaining captive customers. An effective stranded cost recovery program could help prevent such cost shifting and provide a fair transition for regulated utilities. The draft power plan identified some principles for recovering stranded costs, while pointing out that these costs were not likely to be as large in this region as in some others:
The Steering Committee addressed the issues of ensuring competitive conditions in regional electricity markets and the transition to those markets in its section entitled, "Consumer Access to the Competitive Market — Ensuring the Benefits of Competition for All." Support for environmental protections and other public purposes were addressed in the section on "Conservation, Renewable Resources and Low-Income Energy Services — Reflecting the Values and Meeting the Needs of Northwest Citizens."
The Steering Committee concluded with recommendations to ensure competitive conditions in the electricity market and, in addition, addressed consumer protection policies and changes in regulatory practices. It also identified a number of transitional steps that included unbundling of both consumers’ bills and of vertically integrated utility structures, open access to transmission and distribution systems, pilot retail access programs for small consumers, establishing a "provider of last resort" to ensure continued affordable service for all consumers, and establishing a method to deal with stranded costs.
To ensure that competitive conditions exist in the electricity generation and marketing industry, the Steering Committee recommended several actions. Market access should be ensured by providing open non-discriminatory access to transmission and distribution systems. Further, the Steering Committee recommended that the generation and marketing of electricity be separated from its distribution and transmission. Similarly, consumers need access to education and information to inform their market choices. Unbundling of electricity bills into the components of service is part of this requirement, but general consumer education programs are also needed initially to help the retail market develop.
Protection of small consumers was an important concern of the Comprehensive Review. To promote this, the recommendations included ensuring that consumer protection laws were extended to unregulated electricity markets, establishing registration and licensing standards for energy service providers, and establishing a consumer complaint and arbitration process. An important part of protecting small consumers was the resolution of the stranded investments issue, although the Steering Committee made no specific recommendations on how this should be done.
Funds to support the actions recommended in the section on conservation, renewables and low-income support were to be collected by the regulated portions of the industry in a manner consistent with competition in electricity generation and marketing. That is, the funding mechanism should be competitively neutral.
Most importantly, the Steering Committee set a timetable for these changes. It recommended that choice of suppliers be available to all consumers by July 1999. Further, it linked market access to the funding and implementation of the public purpose aspects of its recommendations.
The Comprehensive Review achieved a great deal toward developing a consensus about changes in the regional electricity system. The proposed changes are important and far reaching. The recommendations, however, lack many implementation details. In addition, some of the recommendations seem inconsistent with other recommendations. This section describes and expands on these issues.
Perhaps the most important dilemma raised in the recommendations from the Comprehensive Review is the suggestion that utilities’ distribution functions be separated from their electricity marketing functions. The Comprehensive Review recommendations and the Council’s draft power plan are both very clear that separation is a necessary condition for a competitive market to develop in retail electricity supply. Without separation, there is a great potential that too much market power will be vested in the incumbent electric utilities or their future marketing affiliates. The final report from the Comprehensive Review described in some detail a new distribution entity and a new power marketing entity. The required separation of these entities was discussed in the recommendations as well as in the draft power plan. Both documents stopped short of recommending legal divestiture, but the difficulty of regulating affiliate transactions was recognized.
In the case of investor-owned utilities, there is an established, independent regulator that could enforce an administrative separation of generation and marketing from distribution. Such regulation may prove difficult and will create new regulatory responsibilities and costs. The difficulties of separating regulated from competitive aspects of existing utilities were well illustrated by the Portland General and Enron merger proceedings at the Oregon Public Utility Commission. It is very difficult, for example, to allocate a utility’s value between stockholders and ratepayers.
In the case of publicly owned utilities, the regulator is the locally elected board or commission. The board is responsible to the ratepayers for the activities of the generation and energy sales parts of the utility, which should be competitive functions, and the distribution function, which will likely continue to be regulated. In a competitive electricity supply market, these boards are confronted with built-in conflicts of interest. On the one hand, the board is responsible for seeing that the energy sales part of the utility is an effective competitor able to cover its costs. On the other hand, the board is responsible for seeing that the distribution function offers open, non-discriminatory access to competing electricity suppliers. The Steering Committee offered no solution to this problem, but it is important that the problem be addressed before retail competition can be achieved.
One solution to this problem is actual separation of the utility. The distribution or wires part of the utility could become a publicly owned entity that has as its main focus providing safe and reliable distribution services and facilitating open market choices for all consumers. The generation and marketing portion of the current utility could become a customer aggregator without special access to customers, customer information, or any ability to restrict electricity trade. The latter entity needs to be equipped to compete in the electricity supply and services market.
There are other unique problems that governments and publicly owned institutions face in a market environment. Regulated monopoly utilities were able to share many risks with their customers, in exchange for limitations on their allowed profits. Utilities facing competition will inevitably experience both profits and losses as their business decisions result in costs that are below or above market prices, respectively. The stockholders of investor-owned utilities will be the clear recipients of profits and the clear bearers of losses. The customers/owners of a publicly owned utility do not have such clearly defined responsibility for the utility’s losses as have the stockholders of an investor-owned utility. When the publicly owned utility’s costs are below market prices, its customers will happily accept discounts. But when the costs are above market, those customers with options will exercise them through such measures as self-generation, fuel-switching, relocation or, in a competitive market, purchasing from other suppliers. This will leave the above-market costs for the utility to recover through other means. The above-market costs could be concentrated in the bills of remaining consumers or, more appropriately, they could be recovered through a stranded-cost recovery mechanism. In summary, public utilities currently have no one who has signed up to bear the potential risks of competition. They are, therefore, ill-suited to entrepreneurial activities.
The Steering Committee’s recommendations include some general pricing guidelines. These include unbundling of prices and collection of public purpose funds or stranded investment recovery costs through competitively neutral charges on distribution access. The recommendations did not elaborate on what level of unbundling should be pursued or what constitutes a competitively neutral collection of funds. This section elaborates on the issue of electricity pricing because prices are the key piece of information that makes the market an effective allocator of resources. Regulated prices frequently have failed to provide the cost signals needed for consumers and producers of electricity to make efficient decisions. As the region ventures into restructuring, it is important to understand what role prices play in resource decisions, and it is important to ensure that regulation and competition are blended in a way that permits prices to play an effective role in efficient resource allocation.
The efficiency of competitive markets is dependent on marginal cost pricing. That is, products and services are priced at the cost of producing one additional unit of the product or service. When commodities and services are priced at their marginal costs, consumers and producers are led to efficient consumption and production decisions. This has been the basic tenet of economic theory and practice for a hundred years or more. In the short run, effective competition in electricity generation, for example, would drive electricity commodity prices toward the operating cost of the last generating unit needed to meet demand. In the long run, prices would tend toward the capital and operating cost of the most competitive new generating unit that could be built to meet growing electricity demand.
Regulated electricity prices, in contrast to competitive prices, have typically been set at the average cost of production. Further, several sorts of products and services have been bundled into one price for delivered electricity services. The prices consumers paid, and the prices producers received, did not reflect marginal costs of providing the service. When the Council developed its first three power plans, the costs of adding new generation were far above the average cost of the existing power system, and with few exceptions were also above retail electricity prices. This inaccurate price signal was the primary rationale for programs to secure electricity conservation measures that were lower in cost than the avoided cost of additional electricity generation. By bundling all electricity services, such as transmission, distribution, conservation and reliability, into the commodity price, consumers and producers saw no price information at all about those individual services nor about the commodity by itself. The choices made regarding the composition of electricity and related electricity services were not informed by any market feedback.
Operating decisions should be based on the marginal cost of additional kilowatt-hours of generation. Capacity expansion decisions should be based on the marginal cost of additional capacity. Although energy and capacity costs have often been separated on consumer’s bills as a demand charge and a kilowatt-hour charge, the bill shares have not always been an accurate reflection of their respective costs. Often, the kilowatt-hour charge has borne much of the capacity cost as well as the cost of other service components and overhead. The tendency, in this case, is for large consumers to pay a larger share of the capacity costs than may be warranted by their capacity requirements. At the same time, larger consumers tend to pay relatively low prices per kilowatt-hour. Thus, it should be understood that separating bills into their various components may result in a shift in the share of costs that are borne by various types of users. If done correctly, however, those shifts should result in a more equitable allocation of costs.
The Steering Committee’s recommendations did not specify the exact form that unbundling should take. To some degree, this is appropriate. The exact form of unbundling will evolve with the market. This is especially true in the large industrial market where the types and numbers of separate competitively priced services will depend on the needs of consumers and the marketing strategies of suppliers. However, in the case of smaller consumers, some minimum level of unbundling may be desirable in order to highlight the nature of the choices available and to educate consumers about the components of cost they pay. At the very minimum, distribution costs need to be separate from electricity commodity supplies. To choose among commodity suppliers, for example, customers must be able to compare a commodity price to a commodity price. In addition, customers need the pricing information on other service components to estimate the total cost of electricity service. Additional unbundling may be important to highlight specific components of costs, such as peak or capacity electricity supplies, which may affect the capacity charge included in the electricity or the distribution service. Once the small consumer market becomes well established, the unbundling detail will evolve on its own and specific unbundling requirements are unlikely to be necessary.
The Steering Committee recommended that stranded costs and public purpose funds be recovered through competitively neutral means. It did not specify, however, what constituted a competitively neutral recovery mechanism. Recovery of public purpose funds or stranded costs in a competitively neutral manner requires that the price a consumer faces for an extra unit of product or service remain equal to the marginal cost of providing the product or service. An access fee would affect all suppliers equally and would not affect marginal decisions for capacity or energy. It would therefore be competitively neutral. Adding a charge to the variable component of a consumer’s price for electricity or distribution services violates this principle because it changes the marginal cost signal. Similarly, adding the costs to a demand charge that is intended to reflect the marginal cost of capacity would distort the price signal for capacity utilization and expansion. Recovering the cost through a system access fee, however, leaves the marginal cost signals unchanged.
Both the Council’s draft power plan and the Steering Committee’s recommendations recognized that information is the lubrication that makes competitive markets work well. This is why prices, as discussed in the previous section, are important. They carry a great deal of information back and forth between consumers and producers. In addition to price, there are other types of information that are important to the market. These include information differentiating among the services suppliers offer and the demands of various consumers. It is useful to distinguish consumers’ access to information about suppliers from suppliers’ access to information about consumers. The first allows consumers to choose among alternative suppliers and service configurations. The second allows the suppliers to tailor products and services to specific markets. Such information is one of the keys to how markets promote innovation and increased consumer choice.
In the first case, it can be assumed that marketers will readily provide information about their products and services. It may come in the form of junk mail or phone calls at supper time, but it will be provided. The concern is that the information be reasonably accurate and readily comparable. The Steering Committee recommended that considerable information be required on consumers’ electricity bills, including sources of power, costs and a consumer satisfaction index. It would be more valuable to consumers if such information were readily available before they made their choice of electricity supplier. For example, a service that compiled information about prices, service choices and special electricity characteristics for various providers would be valuable. Information arrayed in a way that promotes comparisons of the key characteristics of products and services offered by various suppliers would be particularly effective in aiding consumers with their choices. The more accurate and easily compared supplier information is, the more effective consumer choices will be in promoting innovation and efficiency. Unbundling of the various components of service will help consumers make comparisons among offerings of alternative suppliers. The information needs to be clear about which services are provided in the package and which may need to be acquired from another source or at extra cost.
A special area of concern is where efforts are being made to bring consumer choice and markets to bear on specific public goals. An example is green marketing. It will be important that electricity marketed to consumers as green power meets public policy objectives and provides enough information to allow consumers to exercise their particular preferences about sources of renewable or clean energy. This is discussed further in the section of this plan dealing with conservation and renewable resources.
The second type of information, market information about consumers, has received less attention in restructuring discussions. It is complicated by the fact that the existing electric utility has a near-monopoly access to such information as levels and patterns of consumption for individual consumers or small market areas. They come by this information naturally as the utility that sells and delivers the electricity to consumers. Release of this information faces confidentiality issues. At the same time, however, possession of such information in a restructured environment could give the marketing affiliate of the existing utility a distinct advantage in a competitive electricity services market. If excess market power problems are to be avoided, this information must be available to an equal degree to all electricity marketers.
For various reasons, the collection and dissemination of information about consumers may need to be centralized within service areas. The entity that is doing the metering and billing is the most logical choice, but there is no reason for metering and billing to be monopoly functions. These services could be provided by the distribution utility, but they don’t need to be. Ideally, one would like to see an incentive for innovation and efficiency in metering, billing and information compilation. New types of information about consumers may prove very valuable in a competitive energy market, and these new types of information may require changes in metering technology. A competitive market can readily determine whether more sophisticated metering technology is worth the extra cost it may involve.
Another information need that may be important, especially during the transition, is aggregate consumption and price information. That is, information on trends in total electricity consumption, average prices paid by consuming sector, and the composition of demand. Such information will be needed during the transitional period to judge the degree and effectiveness of competition, whether costs have been shifted among consumer groups, and whether public policy goals are being met. However, without some specific reporting requirement to a responsible entity, such information will not be made readily available in a competitive environment, especially if the metering and billing are carried out by various competing entities. As the market develops, central collection of such information may become less important and private entities may take over the collection and sale of information that the market itself finds valuable.
The Steering Committee’s recommendations include a number of new public responsibilities, but there is little direction regarding how those responsibilities would be administered or supported. Some of these responsibilities in the area of competition include providing consumer information services; monitoring and enforcing competitive conditions; developing and evaluating pilot programs; ensuring reasonably consistent market conditions and requirements for all participants and states; devising consumer protection laws and their enforcement; registering and licensing energy service providers; implementing a consumer complaint and arbitration process; and creating and administering a universal service fund.
Provision should be made for many of these services to be funded through a competitively neutral distribution system charge, as has been proposed for other public purposes. The funds should be allocated to accountable public bodies for administering these programs. Some of these functions could be carried out by public utility commissions or by the boards and commissions of publicly owned utilities when they have been converted to distribution-only entities. Others could be carried out by existing public agencies. Public agencies could include state consumer protection and business licensing agencies, the Federal Energy Regulatory Commission, the Federal Trade Commission, or the Northwest Power Planning Council.
These types of accountability and administration problems should be addressed in the funding of conservation, renewable resources and low-income efforts as well.
The Steering Committee recognized the importance of addressing stranded costs, but it included little discussion of stranded costs or guidance on how they should be recovered. The term "stranded costs" is often used rather loosely, and discussions reveal that there is not a good understanding of what stranded costs are, how they could be evaluated, or how to provide an equitable recovery of such costs. This section explains what stranded costs are and discusses the reasons for the recovery principles that were included in the Council’s draft power plan.
When the electricity industry was more regulated, recovery of costs was assured by setting electricity prices at a level that covered variable costs and allowed a specified rate of return on invested capital. In a competitive industry, prices are set by the market. Market prices may or may not be adequate to cover a utility’s full investment and operating costs. Stranded costs include capital or sunk costs that cannot be recovered in the competitive market. Stranded costs may also include some regulatory assets, such as qualifying facility contracts under PURPA and capitalized conservation costs. Some other unavoidable costs, for example, required environmental mitigation, may also become stranded.
By definition, variable or operating costs can be avoided if generation is not operated. Therefore, these costs cannot be stranded.
The amount of a generating plant’s cost that is stranded only becomes clear over time. In each year, the stranded cost is the difference between the year’s payment on the plant’s total investment cost (including the allowed return on investment), minus the year’s "operating profit." Operating profit is the difference between the market price of power and the plant’s operating costs. Stranded costs, as calculated above, can be either positive (stranded cost) or negative (windfall profits).
If the market price of power is enough higher than operating costs to recover the investment plus a reasonable rate of return, then there would be no stranded cost. Stranded costs would occur when the market price of power is not sufficient to allow for recovery of capital plus a rate of return comparable to that received under regulation. If, on the other hand, the market price was high enough to create a rate of return of invested capital that is higher than the regulated rate, the utility will receive windfall profits.
Stranded costs cannot be known with certainty now because neither future operating costs nor future market prices are known. Recovery of stranded costs could be based on a one-time estimate of future stranded costs, or recovery could be based on a series of one-year determinations as each year’s stranded costs are revealed. Most discussion has focused on the one-time estimation approach. Two types of estimation could accomplish this. One is to estimate future costs and prices based on either current prices and costs or on modeling and forecasting of their future values. A comparison of the estimated operating profit to sunk costs, which are reasonably well known, [ The exception is some special circumstances such as nuclear plant decommissioning costs or fish and wildlife mitigation. These are sunk costs, but the amount is still unknown.] would provide an estimate of stranded costs. The second approach is to allow the market to place a value directly on the generating asset and compare this market value to the regulated book value of the asset. This would require a sale of the generating plant or an independent assessment of its value.
The discussion above has been about individual plants for the purposes of illustrating the stranded cost concept. But this is not the way that stranded cost recovery should be implemented. Most utilities have more than one generating asset. Some of those generators may prove to have stranded costs, others may earn extra profits beyond what would have been allowed under rate-of-return regulation. Shareholders and customers have a stake in the entire utility, not in specific generating plants. Therefore, it should be clear that stranded costs, for the purposes of recovery, should be assessed at the utility level, not the generating plant level. A utility’s stranded costs should be the net-stranded cost of all of its generating assets. The methods of estimating stranded costs discussed above still apply at the utility level. However, some other alternatives for market valuation of assets, for example a stock re-issuance or similar scheme, may become possible at the utility level.
As in the case of individual plants, this amount may turn out to be positive or negative (windfall profits). If consumers are going to help pay stranded costs, they should also share in windfall profits. The two measures are exactly analogous and are computed by exactly the same formula. Thus, any stranded cost recovery proposal should apply equally to positive or negative stranded costs.
Once stranded costs or windfall profits are determined, their recovery or sharing should follow the principles of competitive neutrality, accountability and efficiency incentives discussed above for public purpose programs. Since operating costs are to some degree under the control of the generation operator and owner, care needs to be taken to keep incentives in place to control and reduce operating costs. If the owner were guaranteed recovery of capital costs on an ongoing basis, even if he operates his plant in an inefficient manner, there would be little incentive to compete, and consumers would be stuck with higher than necessary costs. If, on the other hand, a portion of the stranded cost or windfall profits stays with the owner, or if the amount of stranded cost recovery is set once and has no further effect on owner operating decisions, then the owner has an incentive to keep operating costs as low as possible. Since utility investments, even under regulation, were never considered completely risk-free to investors, it can be argued that some sharing of stranded costs or windfall profits between consumers and shareholders is appropriate.
Stranded cost recovery is probably a fair and necessary transitional policy. However, it is important to understand that if not implemented correctly, stranded cost recovery could dampen the incentives of businesses to create consumer benefits through aggressive competition. Even if done correctly, stranded cost recovery could offset some of the flow of benefits to consumers as they help pay off the stranded investments. The policy objective should be to make a firm determination of stranded costs, which will not be affected by future utility market decisions, to provide for the recovery of those costs in a market-neutral manner, and to limit the duration of the recovery period. The sooner these holdovers from the regulated era are resolved, the sooner the benefits of competition will be realized.
The Council has traditionally addressed conservation and renewable resources independently of one another because the concern was their relative contributions to an integrated resource portfolio. However, in the Draft Fourth Northwest Power Plan and during the Comprehensive Review of the Northwest Energy System, conservation and renewable resources, along with low-income energy services, were addressed together because they raise similar issues in a competitive industry.
In Chapter 6 of the draft power plan, the Council identified 1,535 average megawatts of conservation potential in the region that could be cost-effectively developed over the next 20 years. The Council’s draft power plan estimated that the Northwest could reduce the present-value cost of meeting its need for electricity by roughly $2.3 billion if these energy-efficiency opportunities were fully exploited. In addition, these efficiency gains could reduce the emission of carbon dioxide into the atmosphere by approximately 80 million tons. While the draft power plan acknowledged some uncertainty in the conservation analysis, sensitivity tests indicated that there was substantial long-term value in securing the remaining efficiency improvements over a wide range of conditions.
The Council observed that the implementation of conservation resources faces a radically different environment today than in the past. Specifically, the Council noted that alternative resource costs avoided by conservation are about 50 percent lower than they have been in more than two decades. In addition to reducing the relative cost-effectiveness of conservation measures, this situation now means that some consumers’ retail electricity rates are higher than the cost of developing new power plants. The Council also anticipated that competition will result in a trend toward unbundling of electricity rates — separating the costs of the kilowatt-hours delivered from the fixed costs of delivering the electricity and thereby lowering the apparent price of the kilowatt-hours. Such unbundling will permit consumers to compare their supply alternatives, including conservation, on an "apples-to-apples" basis. These lower prices and unbundling will reduce the disincentive utilities experience when conservation cuts into their recovery of fixed costs. On the other hand, it will also reduce the consumer’s economic incentive to conserve because their rates will likely be lower.
The Council further observed that in the past, Bonneville and the region’s utilities were well positioned both economically and institutionally to acquire all cost-effective conservation. It also noted that competitive pressures, as well as lower avoided costs, are quickly changing this situation. Bonneville has already reduced its conservation investments because it must compete in an "open" wholesale power market and in light of lower avoided costs. It is difficult to compete on the basis of the price of the electricity commodity if that price includes additional costs, such as systemwide conservation funding, which competitors’ prices do not include. As competitive pressures increase in retail power markets, both public and investor-owned utilities can be expected to reduce their efficiency efforts in a similar manner.
The Council anticipated that these changes in the electricity industry will lead to the development of only about one-third of the regionally cost-effective conservation potential — those savings obtained as a result of market-induced conservation and existing utility conservation commitments. Therefore, the Council estimated that of the $2.3 billion in savings that can be expected if all cost-effective conservation is developed, approximately $1.7 billion falls into the category of savings that seem unlikely to be produced through near-term utility commitment or, in the long run, by a competitive electricity market.
Based on its analysis, the Council outlined two alternative policies for the region to consider. Under the first option, the Northwest could focus its efforts on developing more competitive electricity markets and wait to see what the effect is on conservation acquisition. Conservation acquisition over the next three to four years is likely to be relatively substantial because many utilities still intend to pursue conservation development, there is still some carry-over funding for conservation acquisition from previous years, and some government programs also will garner energy savings. In the longer term, this policy option presumes that a portion of the region’s existing conservation industry will develop viable business strategies that do not rely on continued utility or other public investments.
The second policy option assumes a more aggressive response is needed to ensure that conservation’s potential economic and environmental benefits are captured. Under this option, the region would establish alternative mechanisms for developing conservation in an increasingly competitive electricity market. The Council suggested that the Comprehensive Review and appropriate state forums evaluate the costs and benefits of potential mechanisms to acquire conservation beyond what will be developed in the market. The Council recommended that the goal of these activities should be to establish a competitive market for electricity services that preserves as much of the net conservation benefit as possible.
Specifically, the Council recommended that these alternative mechanisms reflect the six principles outlined below.
Unlike conservation, the draft power plan found that few renewable resources are economically competitive with new natural gas fired, combined-cycle combustion turbines, and virtually no renewable resources can compete with current wholesale electricity prices. Consequently, little market-driven development of renewable resources can be expected for the next five to 10 years.
An analysis of the value of preserving renewable resources confirmed that few renewable resources are likely to be cost-effective in the near-term. However, as described in the Global Climate Change Considerations section of this Addendum, the value of renewable resources is very sensitive to the cost of possible climate change control measures.
A second analysis, of the economic merits of a sustained renewable resource development policy, concluded that there is little economic value in augmenting market-driven renewable resource development, even considering the economic risk associated with global climate change. Renewable projects developed in advance of need and cost-effectiveness might accelerate the improvement of resource cost-effectiveness, but would require a significant subsidy. From an economic point of view, the most prudent approach is to defer renewable resource development until the nature and extent of climate control measures are clear. Underlying this conclusion is the assumption that we will not lose the ability to develop renewable resources rapidly and efficiently if the industry in this country is allowed, in effect, to go dormant for several years.
The draft power plan proposed the following general renewable resource actions as suitable for the current environment of surplus capacity and low electricity prices. These actions are intended to support the renewable resource objective of the Northwest Power Act [ "To encourage the development of renewable resources in the Pacific Northwest."] while maintaining the principle of developing resources only as they become cost-effective:
The Comprehensive Review Steering Committee addressed the issue of how cost-effective conservation and renewable resource (and other public purpose) goals could be sustained both during and after the transition to a competitive electricity market. The Steering Committee acknowledged that the market for energy-efficiency services may not capture all cost-effective conservation. Similarly, the Steering Committee concluded that potentially valuable renewable resource technologies, which are not economically competitive in today’s electricity market, may benefit from regional investments that reduce their future costs. The Steering Committee also recognized that competitive markets are unlikely to provide low-income households the means to meet their basic electricity needs at the same level and quality they currently enjoy.
To ensure that cost-effective conservation, renewable resource development and energy services for low-income households are sustained during the transition to competition and beyond, the Steering Committee recommended that by July 1, 1997, and annually thereafter for a period of 10 years, 3 percent of the revenues from the sale of electricity services in the region ($210 million, based on 1995 revenues) be dedicated to those purposes. These funds were to be collected either voluntarily by local utilities or as a result of state action establishing a non-bypassable, local distribution system access charge. In either case, it was intended that funds be collected in ways that do not distort the competitive balance between competing suppliers. The Steering Committee recommended that this commitment should be re-evaluated after 10 years.
The Steering Committee also recommended that a regional technical forum be established to track progress toward the achievement of regional goals, and provide feedback and suggestions for improving the effectiveness of conservation and renewable resource development programs. This forum would also conduct a review of the region’s progress at least every five years and report its findings to the region’s decision-makers.
The Steering Committee expressed a preference for using methods that rely on market forces wherever possible to achieve the region’s goals for developing cost-effective conservation and renewable resources. Implicit in this preference is the principle that the funding dedicated to conservation and renewable resources should, to the greatest extent possible, be used in ways that foster and/or complement the development of competitive markets for energy-efficiency services and renewable resources. In addition, the Steering Committee’s recommendations regarding consumer access to competitive electricity markets are intimately related to the achievement of its public purpose goals. Specifically, the Steering Committee recommended that tariffs, rates or other fees imposed to collect the funds to be used to support conservation, renewable resources and low-income energy services be implemented simultaneously with implementation of open retail access. This relationship between the timing of open retail access and the collection of funds was deemed an essential element in the strategy to ensure a smooth transition to a more competitive electricity industry. Key recommendations specific to conservation and renewables are described below.
Approximately 70 percent of the total funds to be collected for public purposes ($170 million, based on 1995 revenues) was to be di
