In January of 2005, the Department of Public Service (DPS) released The Vermont Electric Plan. This document is an update to that Plan. The purpose of this update is to serve as a supplement to the 2005 Electric Plan, acting as a bridge of support for the public engagement process leading to the development of the next Vermont Electric Plan, in 2007. This update is not intended to present a comprehensive exposition of electricity issues facing Vermont.
Vermont is confronting key challenges and decisions over the next decade. The Department of Public Service believes that public and stakeholder involvement in these decisions is essential to a sound energy planning environment. This update provides up-to-date information about key features of the electricity environment that have emerged since the release of The Vermont Electric Plan-2005, centering on the facts in order to properly frame the challenges and opportunities ahead, and facilitating an informed dialogue.
The Update to the 2005 electric plan frames issues within the statutory directive provided by the legislature in 30 V.S.A. §202, which requires that the electric plan ensure,
. . . to the greatest extent practicable, that Vermont can meet its energy service needs in a manner that is adequate, reliable, secure, and sustainable; that assures affordability and encourages the state’s economic vitality, the efficient use of energy resources and cost effective demand side management; and that is environmentally sound.
Although not mandated, organizing the update to structure issues following this framework eases the transition to the public dialogue for the development of the Vermont Electric Plan – 2007.
Section 1 begins with a summary of emerging challenges and recent developments that have elevated energy issues as a major concern to the public and to policy-makers. No issue in Vermont seems to loom larger in the present energy planning environment than the approaching gap between committed electricity supply and expected demand. In addition, the environment, reliability, system adequacy, costs of electricity and associated drivers, and the changes in New England wholesale markets represent other important areas of concern to policy-makers.
Section 2 presents major policy responses and areas of activity by federal and state lawmakers, regulators, and Vermont utilities since the 2005 Plan was issued. Both federal and state lawmakers have been active in advancing new energy and environmental legislation. The same can be said of federal and state regulators. Vermont utilities are in the process of developing a plan to replace existing resource contracts and commitments.
Section 3 follows with an updated forecast of electric sales and demand. For the first time, the forecast incorporates systematic treatment of Demand Side Management (DSM) program activities in the State, both past and future, by incorporating the influence of those programs, and adjusting for the decay of DSM programs activities. The last forecast of electricity demand performed by the Department was in 2002. In the future, the Department plans to place increasing reliance on an all-fuels, integrated planning model using system dynamics as the basis for the DPS forecast.
Planning efforts among Vermont utilities, at the Department, and more recently, the Vermont General Assembly have emphasized the importance of more effective public outreach and involvement in our resource decisions. Section 4 will discuss recent initiatives and describe the broader public engagement process that is underway as a joint effort of the Department of Public Service and the Vermont General Assembly to help inform future Plans.
It should be reiterated that this update is not intended to set or advocate for particular policy choices. Instead, it is hoped that the information within the following pages will encourage informed dialogue about our energy future with an eye toward creating a Vermont Electric Plan - 2007 representing the collective interest of the State of Vermont.
SECTION 1 – FRAMING THE CHALLENGES: RECENT DEVELOPMENTS AND EMERGING REQUIREMENTS
Despite the brief interval of time since the last Vermont Electric Plan was published, there has been a steady flow of significant events surrounding electric energy policy, fueling a mounting focus for policy solutions. Stimulating this flow are significant developments in energy markets, particularly natural gas markets.1 Natural gas is the key driver of electricity prices in New England; the region learned how vulnerable it is to events up the pipeline, as evidenced by the effects of Hurricanes Rita and Katrina in the 3rd quarter of 2005 on natural gas supplies to New England. When infrastructure was damaged, the price of natural gas and in turn the price of electricity rose dramatically. The nature of electricity markets themselves has also changed significantly and we are seeing the evidence of those changes largely in wholesale markets in New England, but also with recent increases in Vermont retail rates.2
The emerging gap between consumer demand for electricity and contracted or owned generation has emerged as a primary concern to the public and policy-makers. Nearly two-thirds of our current electricity requirements are met through major power contracts for generation with Hydro-Quebec and Vermont Yankee. The bulk of these contracts are due to expire in 2012 and 2015. When these contracts end, Vermonters will still have access to the vast resources inside New England and neighboring areas through the spot market. However, the State may be exposed to more price uncertainty and volatility associated with wholesale electricity. This stands in sharp contrast to our existing long-term contracts. Vermont can manage its market exposure to the short-term market through investments in generation or new replacement long-term contracts; however, these resource decisions also present their own challenges and risks to Vermonters and the State’s utilities.
The challenges and opportunities ahead are a consequence of Vermont’s present circumstance and the events that led us here. In the late 1990s, Vermont resisted the movement toward industry unbundling and retail choice while the rest of New England and the Northeastern U.S. moved toward a more competitive environment that increased exposure to short term and spot market prices. Recently, this has led to a sudden increase in retail prices among most of our immediate neighbors. Under current market conditions, Vermont appears to have benefited by maintaining a vertically integrated structure, as the retail rate for electricity in Vermont is the lowest, on average, in New England.3 This advantage may diminish with the expiration of the aforementioned
1 Oil markets have only a marginal effect on electricity, especially in the New England region where natural gas is often “on the margin,” meaning it is fueling the next generator that is turned on when demand increases. This “marginal” generation is what sets the market price for electricity in each hour. Natural gas is on the margin and setting the price of electricity 55% of the time. As a result, retail prices consumers see at gasoline stations, while often the impetus for energy policy, have little influence on electricity.
2 The rate changes experienced in Vermont, however, are small in comparison to sudden rate increases seen throughout most of the northeastern US. The reasons for the differences will be discussed further below.
3 As of June 2006, the average retail price of electricity in Vermont for residential, commercial, and industrial customers was 13.86, 11.92, and 8.41 cents per kWh, respectively. The New England average for the three sectors was 16.37, 14.76, and 10.53 cents per kWh. The only customer class in New England with lower prices than Vermont’s equivalent class was Maine’s industrial class, at 3.15 cents per kWh.
existing contracts with Hydro Quebec and Vermont Yankee. On the other hand, Vermont could have greater flexibility on a going forward basis to choose to directly invest in new generation or to rely on markets for purchased power.
Wholesale markets first emerged in New England in 1997 and were modified in 2003 to reflect a Standard Market Design that includes a day-ahead market, a real-time market, and a forward reserve market. These markets were added to a pre-existing capacity market. Other Ancillary Service Markets are currently under design and the capacity markets are in the process of being redesigned. Designing capacity and other markets is a complex and involved process, as evidenced by the debate surrounding the Locational Installed Capacity (LICAP) proposal set forth by ISO-New England. The original proposal was widely opposed by interest groups and state agencies alike, including Vermont. The parties have subsequently settled their differences by creating a Forward Capacity Market (FCM). It remains to be seen if FCM and other ancillary markets will encourage the development of additional capacity or foster diversity in supply resources.
For the time being Vermont’s decisions have helped to reduce exposure to energy markets, and the changing “rules of the game.” Over time, our exposure will gradually increase. It is therefore important that Vermont continue to remain active in market development. At present, the region faces an apparent challenge to develop adequate capacity, especially in certain constrained areas due to the threat of inadequate peaking capacity, and challenges to create fuel diversity. Vermont, by reason of its size, can provide limited direct impact on the regional mix, but can impact market design through regional advocacy.
Many other recent developments and challenges are confronting Vermont as well. For the most part, they present new challenges:
· Wholesale electricity price volatility;
· Threats to system reliability and resource adequacy;
· Risks and harm associated with the environment; and
· Security concerns relating to protection of grid infrastructure
A. The Emerging Supply Gap
The current contract with Entergy for unit-contingent power from Vermont Yankee at very favorable prices is due to expire in 2012. The bulk of the Hydro-Quebec contracts expire by 2016. These two resources comprise nearly 2/3 of Vermont’s energy supply portfolio. Only a portion of the remaining electric supply comes from utility-owned resources. Demand continues to grow, albeit at a slower rate than most of the surrounding region. The emerging supply gap presents planning challenges to utilities, regulators, and citizens to ensure stably and reasonably priced service that meets Vermont’s criteria for energy planning. Public engagement efforts to address the resource gap are underway. The Vermont General Assembly, in passing Act 208, focuses a public engagement process on the “electric energy supply choices facing the state beginning in 2012.” The DPS has initiated a Mediated Modeling process in order to provide an easy-to-use model of energy scenarios that will use agreed upon facts in order to inform this debate. Vermont utilities are also engaged in parallel efforts to examine the feasibility of alternatives through integrated resource planning (IRP) and other efforts.
The replacement of these long-term contracts can begin before and end after these contracts end in 2012 through 2015. If we intend to replace these contracts without a gap (i.e., exposure to shorter term markets) by investing in new resources, time becomes a concern. Options can diminish as time passes as the permitting, siting, and (if approved) construction of electric generation requires long lead times. However, there are a variety of reasons to move at a measured pace and consider new strategies for replacing these resources.
First, New England enjoys a competitive wholesale market for electricity. This market can be relied on to help bridge any gaps; it can and undoubtedly will provide at least a portion of the Vermont electricity portfolio for the foreseeable future (almost all Vermont utilities rely on market purchases for a portion of their existing resource mix).
Second, Vermont has historically relied on large single resource or supplier contracts in its resource mix. Although Vermont has benefited from this strategy ongoing reliance on similar arrangements or strategies could create undue risks. Vermont utilities may need to break-up some of its large resource contracts into smaller contracts whose start and end dates vary over time to create less exposure to prevailing market conditions during critical dates.
Third, the relative merits of a significant new generator in Vermont should ultimately be determined by careful consideration of its economics and risk. How much of a cost premium might Vermont be willing to pay in order to protect itself from exposure to the open market? And how well do we understand the underlying economics of either building a generator or relying on the open market?
No single supply resource will be able to fill the gap; replacement contracts with existing suppliers will continue to enjoy favor. Greater consideration will need to be given to meeting our needs through a more diverse mix of resources. In order to meet the electrical needs of Vermonters, the emerging supply gap should be addressed with an informed dialogue and even-handed policy decisions.
B. Wholesale Market Price Volatility; Regional Dependence on Natural Gas for Generation
The New England region saw unprecedented levels of wholesale electric price increases and volatility in 2005. Some responsibility is owed to the effects of Hurricane’s Katrina and Rita, but the region’s heavy reliance on natural gas to generate electricity also plays a large role. This dependence on one fuel source is a fairly recent phenomenon. In 1995, less than 10 percent of the regional energy mix was natural gas. Currently, roughly 40% of the energy sold on the wholesale market is from natural gas. 98% of the region’s capacity additions since 1999 have come in the form of high efficiency natural gas combined cycle generation facilities. Natural gas now sets the market price of wholesale electricity in most hours.
Despite the increases in average prices between 2002 and 2006, natural gas remains a low cost source of generation. Although combustion of natural gas creates emissions far greater than renewable energy facilities, it remains less costly. Among fossil fuels it is by far the cleanest. Thanks to advances in combustion technology with the evolution of gas combined cycle generation, gas enjoyed an advantage over other fuels for fuel conversion efficiency. Historically, natural gas has been delivered to the region via pipeline and has remained free of disruption from instabilities in overseas regions. In broad terms, it has offered both an inexpensive and relatively environmentally benign source of energy. However, the resulting demand increases early in the decade have culminated in concerns over the region’s heavy dependence on the fuel and the risk for supply disruptions.
On a forward going basis, liquefied natural gas (LNG) figures to be an important source of fuel. Continued low prices for natural gas depend on siting liquefied natural gas terminals in the region before 2011, and pipeline capacity from the McKenzie Delta in 2011 and from Alaska in 2015. There are approximately 40 applications with the Federal Energy Regulatory Commission (FERC) nationwide to construct new LNG facilities, however it is expected that only about 12 will ever be built. For any new terminals to affect prices in New England at least one or two may need to be sited in or around the region in order to alleviate infrastructure constraints resulting from transporting the fuel long distances via pipeline. For purposes of the DPS forecast and analysis, it was assumed that one LNG terminal would be sited in the New England or Eastern Canada region.
As noted above, natural gas is not as environmentally friendly as renewable energy, but it is less expensive. It costs more than coal, but is a far cleaner resource than coal or other fossil fuels. In balance, natural gas generation has a competitive advantage to other fuels. However, exposure to supply disruptions, the region’s heavy dependence on a single fuel source, and CO2 emissions associated with the fuel are causes for concern. The relation of natural gas to wholesale market prices is discussed further in Section 3.
C. Threats to System Reliability
The disruptions to supplies caused by Hurricane’s Katrina and Rita did not only create high prices in wholesale markets, they also highlighted the risk that the region saw to the delivery of reliable electric service during critical periods of peak demand for natural gas. In New England, this risk is amplified in the winter when electric generation competes with demands for natural gas as a source of he at. The cold snap that occurred in January 2004 resulting in concurrent regional winter peak electricity and space heating demands also highlighted these emerging tensions in the region. 4 At that time, the New England’s dependence on natural gas as the dominant fuel source for generation came under closer scrutiny. Today, there is growing consensus that fuel diversity, even from single generators in the form of dual or multi-fuel capabilities, has surfaced as a critical requirement for the region as a whole. Threats to system reliability also were revealed in 2003 when a major power blackout affected portions of the mid-western and northeastern US and eastern Canada. The
4 See, ISO-NE’s report, “Northeast Natural Gas Infrastructure Assessment”, April 1, 2005, available at
power outage affected approximately 50 million people and 61,800 MW of electricity demand.5 Power was not restored for portions of the affected area for 4 days. Estimates of the cost of the blackout range between $4 and $10 billion. A task force was created to determine the causes of the blackout and recommend policies to avoid a recurrence of the problem. System operational management inefficiencies were found to have caused the physical problems, but the root causes were found to be failures to perform effectively relative to the reliability policies, guidelines, and standards of the North American Electric Reliability Council (NERC). Deficiencies in the voluntary standards themselves were also identified as problems. There were 46 recommendations to address the failures that led to the blackout; however, chief among the task force recommendations was that the U.S. Congress should enact provisions to make compliance with reliability standards mandatory and enforceable. As discussed below, the Energy Policy Act of 2005 responded by creating policies to make reliability standards mandatory and enforceable with responsibility for such enforcement resting ultimately with the Federal Energy
As demand grows in New England, the capacity needed to supply generation on the peak demand days is becoming increasingly scarce. On August 2nd, 2006, ISO-NE reported record electricity demand, at 28,021 MW, approximately a 4% increase from the 2005 peak of 26,885 MW. Since 2004, peak demand has grown from just over 24,000 MW to over 28,000 MW.6 Five out of six of the highest electricity demand days have been in 2006, and nine out of ten have been in the last two years. However, over the same time period little capacity has been added to the region, even though forecasts call for increasing demand and a continually increasing peak. While the recent peak was managed well by ISO-NE, concerns over capacity constraints threatening reliability and leading to emergency actions and volatile prices have led to the development of Forward Capacity Markets (discussed in detail in Section 2, subsection E-2). These markets encourage the construction of capacity to ensure the regions electric system reliability.
The flow of energy policy activity summarized in Section 2 can be attributed in large part to the challenges and regional and national developments mentioned above. The emerging supply gap is at the forefront of Vermont policy issues, while regional participation in markets to diversify fuel sources, stabilize prices, and maintain system reliability is essential to Vermont’s social, environmental, and economic well being.
Major decisions are made today in a much different environment than in years passed. Vermont’s neighbors have moved to a competitive retail electricity market, while Vermont continues to remain vertically integrated. Greater public knowledge and involvement adds insight and breadth to the debate over various options. The impact of our energy choices on the environment is more prevalent than ever before. Threats to the security of the electric grid have become a priority concern.
The choices made today will affect Vermont for years to come. Vermont will continue to be active responding to energy issues in the future and the public dialogue resulting from the development of the 2007 energy plan will aid in this process.
SECTION 2 – POLICY INITIATIVES, RESOURCE DECISIONS SINCE THE JANUARY 2005 ELECTRIC PLAN
Over the course of the past 18+ months, changes to Vermont and Federal law, significant regulatory initiatives before the Vermont Public Service Board, stakeholder engagement efforts, and developments in the market have altered the energy landscape in Vermont. These high activity levels show that there is no lack of response or effort by the public, industry, and governments in the region to respond to the challenges and opportunities highlighted above. This section will provide a snapshot of the changes initiated since the Vermont Electric Plan – 2005.
(A-1) The Energy Policy Act of 2005 (EPACT):
The Energy Policy Act of 2005 (EPACT) is the first major piece of federal energy legislation since 1992. The policy is comprehensive, and will have a significant effect on Vermont electric utilities, developers, and ratepayers. EPACT endeavors to provide consumers with reliable, low cost service, while attempting to reduce the nation’s dependence on fossil fuels. The primary avenue contemplated for affecting change is through production tax credits and incentives for research and development. They are offered for nearly every source of electrical energy, including efficiency. 10 In addition, EPACT emphasized the Federal Energy Regulatory Commission’s (FERC) authority to site infrastructure, particularly electric transmission lines and Liquefied Natural Gas (LNG) terminals.
Electric Reliability: In its report on the 2003 blackout, the US-Canada Power System Outage Task Force listed mandatory reliability standards first in its recommendations to prevent future blackouts.11 EPACT created mandatory, enforceable electric reliability standards, under which noncompliance penalties will be enforced. In addition, EPACT gave FERC authority over the siting of electric transmission by requiring FERC to designate “National Interest Electric Transmission Corridors.” After designation, States will have discretion as to where and how the transmission lines will be built, but if the state attempts to obstruct the construction of the line, FERC will assume authority to issue a permit. Vermont was not among the areas chosen for initial designation.
10 A detailed summary of EPACT’s provisions is beyond the scope of this update. For a summary of the EPACT, see the Senate Committee on Energy and Natural Resources Press Office
http://energy.senate.gov/public/_files/PostConferenceBillSummary.doc. The full text of EPACT ‘05 is available from Federal Energy Regulatory Commission, www.ferc.gov.
11 US-Canada Power System Outage Task Force Final Report on the August 14th Blackout in the United States and Canada, April 2004
B. Statutory-Vermont :
During the 2005-2006 session, the Vermont Legislature was actively engaged in energy policy, passing eight significant laws concerning efficiency, renewable energy, and Vermont Yankee, among others. A short summary follows. Major issues considered in each statute are discussed in greater detail in sections below. 13
12 For more information on these rules, visit www.epa.gov/cair/index.html
13 The entire text of each of the Acts listed below can be found at http://www.leg.state.vt.us/docs/acts.cfm?Session=2006.
(B-1) Act 61: Renewable Energy, Efficiency, Transmission, and Vermont’s Energy Future
Act 61, passed in 2005, considered a wide range of energy issues. It created the Sustainably Priced Energy Enterprise Development (SPEED) Program. SPEED encourages Vermont utilities to engage in purchase power contracts with renewable resource developers (Discussed in subsection C-1). In establishing the SPEED program, the Vermont General Assembly targeted instate efficiency and renewables in meeting all incremental load between 2005 and 2013. Act 61 also removed the cap from the energy efficiency utility budget, directing the PSB to determine the optimal level of funding (Subsection C-2). In addition, Act 61 formalized the transmission planning process, requiring more public and local engagement in long range transmission planning (Subsections C-3 and H-2).
(B-3) Act 208: The Energy Security and Reliability Act
During the 2006 session, the Vermont General Assembly passed another omnibus energy law, Act 208. Included among the provisions of Act 208 was a provision for better and broader public engagement on key issues of the day. Act 208 provides for a “comprehensive statewide public engagement process on energy planning, focused on electric energy supply choices facing the state beginning in 2012.” (See D-2 for more detail on the public process area of this statute) It also creates an advisory committee for the “Vermont Clean Energy Development Fund.” The Act established Commercial Building Energy Standards, requires the PSB to create an “Electricity Affordability Program” by January of 2007 (See subsection C-7), and requires the DPS to complete an Affordability Study. The legislature also required the PSB to expand the scope of Vermont’s net-metering program, increasing the maximum kilowatt capacity of facilities that may participate and allowing “group net-metering” systems (See subsection G-6).
SECTION 3: CURRENT AND FORECASTED PRICE AND DEMAND FOR ELECTRICITY
The Vermont 2006 Electric Plan Update provides forecasts for base electricity demand, summer peak electricity demand, winter peak electricity demand, wholesale electricity prices and retail electricity prices in Vermont for the 2006 through 2026 time period. First, the wholesale price forecast is presented as it was used in the development of the retail price forecast. Next, the retail price forecast is discussed, followed by the forecasts of Vermont’s total electricity demand and peak demand. It must be emphasized that with any forecast, but especially with long-term (20 year) forecasts as presented here, certain assumptions must be made regarding future events. The Department of Public Service has made every effort to provide for the accuracy of these forecasts. However, forecasting is far from a precise science, and these forecasts are subject to revision as the facts demand.
The wholesale electricity price forecast was developed through the 2005 Avoided Energy Supply Component (AESC) Study, a regional collaboration designed to analyze the potential for avoiding energy supply costs (including electricity) through the implementation of energy efficiency programs in New England. The study’s avoided costs are in essence a forecast of wholesale electricity prices. This wholesale forecast was used by the DPS in the development of its Vermont retail price forecast. As Figure 3-1 shows, there is an expected near-term decrease in the price of wholesale electricity, which bottoms out at $0.0516/kWh in 2010 from a short-term high in 2007 of $0.829/kWh. This forecasted decrease in price is closely related to the forecasted price of natural gas.
Approximately 40% of the electric generation capacity in New England is fueled by natural gas. These generators are often on the margin and setting the price of electricity in most hours. As a result, electricity prices have tracked prices for natural gas (Figure 32). This is expected to continue, particularly in the near-term.
As an energy source for Vermont and the region, LNG brings with it significant uncertainties. For the fuel resource to affect prices and reliability in New England, siting of terminals and storage in or near the region is necessary. One plant has been proposed for Fall River, MA, another in Canada. In addition to infrastructure needs, New England and the rest of the country will be competing for supply with developing nations. It is not certain the United States will be able to gain access to LNG in quantities great enough to meet demand. Prices of natural gas, and wholesale prices of electricity, will depend heavily on the infrastructure for and access to LNG. These prices will, in turn, affect the
The annual demand for electricity in Vermont averaged a 1.27% growth rate from 1990-2000. From 2000 - 2005, the average annual growth rate was only 0.89%. The slower rate over the last 5 years can be attributed to a number of factors, including a greater emphasis placed on demand-side management programs. Tables 3-1 and 3-2 present the historical electrical sales data for Vermont since 1990.
This Electric Plan Update provides an annual forecast for base electricity demand in Vermont, at the retail level, for the 2006 – 2026 time period. It also provides an annual forecast for summer and winter peak demand, at the wholesale level, over the same time horizon. The forecast considers what the future demand (both base and peak) for electricity in Vermont may look like under two scenarios: 1) If new Demand Side Management (DSM) programs are pursued to their full cost-effective and achievable potential40 and 2) if no new DSM programs are implemented after 2008. This second scenario is not a projection of the status quo. DSM programs have been in place in Vermont for 16 years and can be expected to continue at some level. The “Without Future DSM” scenario is intended to examine what Vermont’s electric energy demand may look like if these programs ceased all together. The forecast includes the existing stock of DSM, annual additions to this stock and annual reductions attributable to decay. The decay rate is a measure of the life of an efficiency measure and can range between 1 and 30 years. For example, compact florescent light bulbs (CFL) have an estimated life expectancy of 4 years; the electricity savings attributed to CFLs installed in 2006 can be expected to exist through 2010, after which electricity demand would rise by an amount equivalent to 100% of the savings. In order to capture present and future changes in technology, Energy Star requirements, consumer behavior, etc, that could lead to increased efficiency, this forecast uses a decay rate that is half of the current rate for historical DSM measures. The lower decay rate serves as a proxy for a multitude of factors that can be expected to partially mitigate the decline in historical DSM measures. The “With New DSM” scenario assumes new additional DSM savings averaging approximately 88,624 MWh per year, through the year 2015. These incremental savings are then expected to decline to an average annual amount of 51,797 MWh of new savings. The “Without New DSM” forecast calls for no new DSM programs after the current EVT contract expires at the end of 2008. The only DSM effects that persist will be those of the existing, but declining, DSM stock. This stock is assumed to decay just as the DSM stock does in the “With New DSM” scenario.
The forecast does not assume any structural changes in rate design or pricing mechanisms per se, but it does include a price forecast that considers the impacts of increased or decreased levels of DSM on price. The forecast also includes projected future values for DSM under the two scenarios. The methodology used to develop the forecast, along with the associated statistical tests, can be found in Appendix B.
Base Electric Demand (Base Load Forecast)
Base electric energy demand represents the overall amount of electricity consumed by Vermont in a given year. This analysis considers base electric demand at the retail level (after all losses that occur between the point of entry to the grid through to the consumer’s meter). The forecast model includes factors representing the amount of electricity provided historically by utilities, the estimated DSM savings provided by Efficiency Vermont and Vermont utilities, population, real disposable personal income, the unemployment rate, and the retail price of electricity. Historical data series over the 1986 – 2006 time period were used to estimate the l coefficients for each of these variables.
If DSM programs are implemented as prescribed in the Department’s recent report, Vermont Electric Energy Efficiency Potential Study, Vermont’s base demand for electricity is expected to grow at an average annual rate of 0.30% (See Figure 3-4).41 If the current levels of DSM, as proposed by the energy efficiency utility, are not continued beyond the 2008 contract period, then Vermont’s base demand for electricity is projected to grow at an average annual rate of 1.36%. Vermont base electric sales have grown at approximately 1.45% per year over the past decade (1995 to 2005). These figures demonstrate both the potential and risk of new DSM programs. If DSM programs are continued at sufficient levels and their anticipated effectiveness is realized, this forecast suggests they could significantly reduce annual base load growth. However, if they are not continued at sufficient levels and/or their anticipated effectiveness is not realized, then Vermont’s base load growth can be expected to continue to grow as it has recently or potentially at larger rates not seen in several years.
Seasonal Peak Demand (Peak Load Forecast)
Seasonal peak electric demand is defined as the greatest use of electricity, in an hour, within the summer and winter periods. Peak electric demand is a major determinant for setting the capacity of an electric supply system because a reliable electrical system is one that can meet every hour of demand. Winter and summer demand peaks are forecasted by applying winter and summer seasonal load factors to a base energy forecast. For purposes of this analysis, the previously described base model is used with an adjustment for line losses that are incurred on the local wire systems. Seasonal load factors are then applied to these “gross” sales figures. The seasonal load factors are essentially the same load factors derived by ISO-NE for Vermont as part of its annual reporting requirements.42
Peak electric use is determined by several factors, most notably the weather and the size of the underlying base demand. In the summer months, temperature and/or humidity can create excessive demand for electricity to run air conditioners. In the winter, extremely cold temperatures can create excessive demand for electricity to provide heat. Such conditions will typically only produce a spike in demand on weekdays when businesses are operating. Furthermore, these spikes in demand typically are part of a larger weather pattern or cycle. In other words, a peak in demand does not usually occur as the result of an isolated hour’s event, but rather occurs at the end of a “build-up period”.
In addition to weather factors, peak electric demand is also determined by the overall size and characteristics of the customer base and how this base responds to changes in the weather over time. Vermont’s economy and population have grown over time and are expected to continue to do so. As this base grows there are more customers to respond to a heat wave/cold snap, so the peaks will grow in size. Since the 1980s Vermont has been moving away from electric heat and has instituted demand management programs such as interruptible service contracts. The effect of these changes has been to moderate the size and growth of the winter electric peak. However, with the growing use of air conditioners in private homes and commercial office space retrofit, the summer peak levels have increased in recent years. The seasonal peak forecast methodology used for this updated Electric Plan considers all of these factors.
The seasonal peak forecast used for this updated Electric Plan is based on work performed by ISO-NE. ISO-NE has developed a comprehensive database that allows it to consider: historic weather patterns (including hourly data), how peak electric demand has reacted to those patterns, and also how peak demand has changed with base electric demand, in each of the six New England states, over time. The forecast methodology developed by ISO-NE is complex and not published. A summary description of the methodology can be found in Appendix B.
In the “With New DSM” scenario, Vermont’s summer and winter peak demands for electricity are expected to grow at average annual rates of approximately 0.53% and –0.86%, respectively (See Figures 3-5 and 3-6, below). In the “Without New DSM” scenario Vermont’s peak demand for electricity is projected to grow at an average annual rate of approximately 1.64% and 1.26%, respectively. This growth is higher than recent history because after 2008, without new additions to the DSM stock, decay in the existing measures can be expected to reduce the state’s consumption-efficiency and correspondingly increase its demand for electricity. Vermont’s summer and winter demand peaks have grown at approximately 2.14% and 0.99% respectively, over the past decade (1995 to 2005), with DSM measures in place. These projected and historical figures indicate both the large potential and risk of DSM, as a tool for managing
Vermont’s capacity requirements. The forecast anticipates both larger and more effective DSM initiatives than have historically occurred. Programs of this anticipated size have never been tried before n Vermont. If these expectations are realized, the forecast demonstrates the very large potential for reducing Vermont’s peak load growth.. Likewise, recent history demonstrates the potential risk—continued higher growth in peak demand—if these programs are not sustained at sufficient levels and/or their anticipated savings are not realized.