An Introduction to Energy, Electricity and Utility Regulation

1. An Introduction to Energy, Electricity and Utility Regulation NRDC Energy Efficiency Advocacy Training

2. Energy, Electricity, andNatural Gas Basics

3. 3 Energy Basics Work = force* distance = energy Fundamentally, humans apply energy to do work The first law of thermodynamics is that energy is neither created nor destroyed We use various conversions processes to convert energy from one form to another During conversion, it is common to lose (not be able to put to use) some of the energy – it is lost to us but not lost in physical sense Most often, what we lose (or fail to use) is heat

4. 4 Energy Basics The earth receives daily from the sun enough energy to do all of the work humanity requires. What we lack are: Sustainable ways of converting various forms of energy into electricity Sustainable ways of directly applying various forms of energy to human needs We have ample energy, but because of the economic, environmental and societal costs of conversion to usable forms, we cannot afford to waste energy we convert on uses that are not valuable Most energy utility prices do not include all (or even most) relevant environmental and social costs Because of cost of service principles, regulated retail electricity prices are often the worst at signaling the full cost As this presentation will explain later in more detail, regulated electric utility prices include a significant amount of cost incurred many years ago in the form of capital investment. That “embedded” cost is further reduced by the amount of the original investment the utility has depreciated over time. Thus, for a generating plant that cost $500 million in 1970, rates in 2000 might include only a remaining, un-depreciated investment of $200 million. As this presentation will explain later in more detail, regulated electric utility prices include a significant amount of cost incurred many years ago in the form of capital investment. That “embedded” cost is further reduced by the amount of the original investment the utility has depreciated over time. Thus, for a generating plant that cost $500 million in 1970, rates in 2000 might include only a remaining, un-depreciated investment of $200 million.

5. 5 Electricity Basics A form of energy characterized by the presence and motion of elementary charged particles generated by friction, induction, or chemical change A secondary energy source, made from the conversion of other sources of energy, like coal, natural gas, and other natural sources, which are primary energy sources Sources of electricity can be renewable or non-renewable, but electricity itself is neither renewable or non-renewable

6. 6 Electricity Basics A kilowatt is 1000 watts; generally called “demand” – the maximum amount of electricity a customer asks for at a given moment, or “capacity” – the maximum amount of electricity a generating resource is capable of producing at a given moment A kilowatt-hour is 1000 watts delivered for one hour; generally called “energy,” whether it is being consumed or produced Common conversions 1 kWh = 3,412 btu (british thermal unit) 1 cubic foot natural gas = 1,028 btu 1 therm = 100,000 btu

7. 7 Electricity Systems At its most basic, the physical electricity system is: a source of generating kWs (a generating plant – G) a way to move that generated electricity at fairly high voltages closer to where it is used (transmission lines – T) a way to move the generated electricity from the transmission lines into commercial and residential areas (distribution lines – D) various substations and transformers that make that generated electricity suitable for use by consumers (step-up and step-down) a meter electrical wiring on the customer side of the meter (often, but not always, inside a structure) every piece of equipment connected to the electrical wiring

8. 8 Electricity Systems The meter is a billing device, not a border to the physical system The electrical system is “instantaneous;” i.e., at any given moment, the amount of power being generated (or pulled from storage such as a battery) must exactly equal the amount of power being used Power flows to load over the path of least resistance Interconnected systems affect each other; disturbances don’t respect ownership lines It is impossible to trace a kWh from the point of generation to point of consumption

9. 9 Ways to make electricity Most current technologies for making electricity involve making heat to produce high pressure steam, which then turns a generator that makes electricity; to make the steam, can use Fossil fuels (oil, coal, natural gas) Nuclear fuels Biomass fuels (wood waste, cellulosic, etc.) Geothermal energy Concentrated solar energy Other technologies include Hydro-electric Wind Photovoltaic solar Hydrogen fuel cell

10. 10 Where electricity comes from in the US You can find the most recent such chart in EIA’s Electric Power Annual. If you simply go to the EIA home page and click on “electricity”, you will find a link there to the latest Electric Power Annual. This is the link to the chart that appears above: http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html You can find the most recent such chart in EIA’s Electric Power Annual. If you simply go to the EIA home page and click on “electricity”, you will find a link there to the latest Electric Power Annual. This is the link to the chart that appears above: http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html

11. 11 How we use electricity We use electricity primarily in structures; exceptions include: Pumps Streetlights, traffic signals Other distributed equipment, e.g., telecommunications relay stations In residential structures, the top three uses are: Central air conditioning Refrigerators Main space heating systems The positions of space heating and air conditioning will change depending on the state US DOE Office of Energy Efficiency and Renewable publishes state-level heating and cooling degree days; with this, you can compare efficiency of space conditioning usage between similar states EIA maintains a lot of helpful information on end use. Much of it is in the Annual Energy Outlook; however, state by state reports add detail and there are specific reviews of customer segments as well.EIA maintains a lot of helpful information on end use. Much of it is in the Annual Energy Outlook; however, state by state reports add detail and there are specific reviews of customer segments as well.

12. 12 How we use electricity Commercial structures Usage often reported by purpose of the structure; e.g., education, retail, office Top uses across many types of structures include: Lighting Cooling Ventilation Refrigeration Industrial structures Usage often reported by type of industry Top uses are motive power and process use Within a given structure are uses that will look the same across the classes, regardless of classification; e.g. office space in a home or factory See notes on prior page.See notes on prior page.

13. 13 How we use electricity Across the type of structures, the (2007) distribution of use is: 37% residential 35.5% commercial 27.3% industrial Percentages will vary by utility Industrial use has been declining for several decades Commercial use and residential use continue to climb More structures (population drivers) More uses within a structure Rise of electronics Adoption of air conditioning The information on distribution of use across customer classes is also found in the EIA website. Look under Electricity and follow the link to “Electric Sales, Revenue, and Price.” The specific chart is “Sales to Bundled and Unbundled Consumers by Sector, Census Division, and State.” The information on distribution of use across customer classes is also found in the EIA website. Look under Electricity and follow the link to “Electric Sales, Revenue, and Price.” The specific chart is “Sales to Bundled and Unbundled Consumers by Sector, Census Division, and State.”

14. 14 Electricity Price History The best source for historical price information (although I cannot find this specific chart) is the “Historical Summary Data Back to 1949” link within the EIA Electricity page. If you follow this, you can find chart 8.10, which appears in both table and chart form. This includes both real and nominal price data, although not in the same chart as appears above. The key here is that the US had real declining prices for about two decades, from 1980 to 2000. In other words, customers “experienced” electricity requiring less and less of their annual income or revenues. It is no wonder there is an implicit assumption that electricity costs should only go “down.” In fact, the primary drivers were what happened in the international markets for oil and natural gas and the “working off” of the excess capacity built in the 1970s. The best source for historical price information (although I cannot find this specific chart) is the “Historical Summary Data Back to 1949” link within the EIA Electricity page. If you follow this, you can find chart 8.10, which appears in both table and chart form. This includes both real and nominal price data, although not in the same chart as appears above. The key here is that the US had real declining prices for about two decades, from 1980 to 2000. In other words, customers “experienced” electricity requiring less and less of their annual income or revenues. It is no wonder there is an implicit assumption that electricity costs should only go “down.” In fact, the primary drivers were what happened in the international markets for oil and natural gas and the “working off” of the excess capacity built in the 1970s.

15. 15 Efficiency of Electricity At the point of generation with fossil-fuels, we lose about 2/3rds of the energy in the conversion to electricity; common conversion losses are: Coal: 36-40% for standard; low 40s for super-critical Natural gas: up to 60% for CCCTs, as low as 35-40% for peakers Nuclear: 30-32% One can also compare fossil-fuel technologies on the basis of heat rate; the lower the heat rate, the more efficient the conversion Delivery losses: T&D losses in the US average 7.2% An individual transformer loses up to 2% in the transformation process For renewable energy generating technologies, can talk about efficiency in terms of watts per square meter 5-20 W/m2 for wind 1 W/m2 for biomass 20-60 W/m2 for solar The operating efficiency of a generating unit is a function of the amount of net heat that it can extract from the energy source for use in the production of electricity. Heat Rate is a measure of generating station thermal efficiency--generally expressed in Btu per net kilowatthour. It is computed by dividing the total Btu content of fuel burned for electricity generation by the resulting net kilowatthour generation. The operating efficiency of a generating unit is a function of the amount of net heat that it can extract from the energy source for use in the production of electricity. Heat Rate is a measure of generating station thermal efficiency--generally expressed in Btu per net kilowatthour. It is computed by dividing the total Btu content of fuel burned for electricity generation by the resulting net kilowatthour generation.

16. 16 Notes for Advocates Utilities typically size their systems for a maximum level of demand, plus a margin for the unexpected A useful number to know if the utility’s annual generation capacity factor Calculated by dividing hours of actual operation by hours of availability; per plant and system-wide A plant in a forced or maintenance outage is not “available” Capacity factors can vary based on variable economics (fuel cost, heat rate) or on fuel availability (water, wind, sun) If a utility’s overall generation capacity factor is low, it is less likely to have a strong case for adding new generation It can also be useful to know the utility’s distribution system capacity factor Often less than 50% because peak demand is much higher than average use A lower CF indicates opportunities to save cost with demand response Sample capacity factor calculation: Coal plant A has a nameplate capacity of 500 MW During 2007, it had a four-week maintenance outage and 7 days of forced outage. In total, the outages were 740 hours. To calculate availability factor, subtract the 740 hours from 8760 hours (the total hours in a year) and divide the result by 8760. In this case, that is about 91.6%. To calculate capacity factor, you need to know how many of hours it actually ran. Let’s say in this example, it ran full-out in January and February, half of March, July, August, November and December, for a total of 4728 hours. Dividing 4728 by 8760, you find that the plant had a capacity factor of almost 54%. As a general rule, base-load generating plants should operate at a capacity factor of 80% or better. Among thermal generating sources, these tend to be coal or nuclear plants. Among renewables, geothermal can operate as base-load and, seasonally, hydro. Intermediate load generating plants may swing around 50% capacity factor, although they can go much lower depending on what other sources of power are available in a given market. Among thermal plants, the most common intermediate base-load resource is a combined cycle combustion turbine plant fired with natural gas. It is not uncommon to find one or more of these plants for a given utility operating at a capacity factor under 20% if the utility is in a market that has ample supplies of coal or nuclear resources. These can typically under-price the natural gas plant. Intermediate base-load resources are also how many utilities respond to the seasonal nature of their weather-related demand. Thus, the plant may run heavily in winter and summer but very little in spring and fall. Sample capacity factor calculation: Coal plant A has a nameplate capacity of 500 MW During 2007, it had a four-week maintenance outage and 7 days of forced outage. In total, the outages were 740 hours. To calculate availability factor, subtract the 740 hours from 8760 hours (the total hours in a year) and divide the result by 8760. In this case, that is about 91.6%. To calculate capacity factor, you need to know how many of hours it actually ran. Let’s say in this example, it ran full-out in January and February, half of March, July, August, November and December, for a total of 4728 hours. Dividing 4728 by 8760, you find that the plant had a capacity factor of almost 54%. As a general rule, base-load generating plants should operate at a capacity factor of 80% or better. Among thermal generating sources, these tend to be coal or nuclear plants. Among renewables, geothermal can operate as base-load and, seasonally, hydro. Intermediate load generating plants may swing around 50% capacity factor, although they can go much lower depending on what other sources of power are available in a given market. Among thermal plants, the most common intermediate base-load resource is a combined cycle combustion turbine plant fired with natural gas. It is not uncommon to find one or more of these plants for a given utility operating at a capacity factor under 20% if the utility is in a market that has ample supplies of coal or nuclear resources. These can typically under-price the natural gas plant. Intermediate base-load resources are also how many utilities respond to the seasonal nature of their weather-related demand. Thus, the plant may run heavily in winter and summer but very little in spring and fall.

17. 17 Natural Gas Basics Supply (2006 data) About 80% (18.5 tcf) comes from domestic sources, and 75% of this from 5 states (TX, OK, WY, NM, and LA) and Gulf of Mexico About 19% (4.2 tcf) is imported and 86% of this is form Canada LNG imports in 2006 were just over 0.5 tcf Gas from the ground first enters gathering systems and then moves into interstate pipelines Over 210 pipeline systems and 302,000 miles of pipeline Many major urban areas have access to two or more interstate pipelines, drawing from two or more natural gas basins; rural areas may have access only to one Gas transfers to local distribution companies (LDCs) at the “city gate” Most LDCs buy gas from marketers or brokers and occasionally a producer Purchases tend to be near-term: a season (6-month strip) to 1-2 years ahead Credit requirements prevent many longer-term deals Flexibility in the system: storage Almost 400 active storage sites (depleted fields, aquifers, salt fields) Again, EIA is the source for good, up-to-date statistics about sources of natural gas. The information above was drawn from: U.S. Natural Gas Imports and Exports: 2007. This is a report found under “analyses” on the Natural Gas EIA home page. Again, EIA is the source for good, up-to-date statistics about sources of natural gas. The information above was drawn from: U.S. Natural Gas Imports and Exports: 2007. This is a report found under “analyses” on the Natural Gas EIA home page.

18. 18 How we use natural gas The top uses for residential and commercial are relatively similar: Space heating Water heating Cooking Industrial use can include these but the largest industrial uses are: Process use; e.g., fertilizer production Steam use: i.e., industry uses natural gas to boil water to make steam for process use Natural gas use has been falling in last 10-15 years Price reaction More efficient structures Wild cards to reverse this trend are: High penetration of NG vehicles Rapid adoption of fuel cells that use NG to produce hydrogen The best source for basic gas use statistics is the EIA Annual Energy Outlook, just as with electricity consumption statistics.The best source for basic gas use statistics is the EIA Annual Energy Outlook, just as with electricity consumption statistics.

19. Utility Basics

20. 20 Investor-Owned Utilities (IOUs) Equity shareholders provide a portion of the utility’s capital needs in return for an opportunity to earn on that investment, typically through dividends and appreciation in the value of the stock shares Types: Vertically-integrated: Own G, T and D Resource portfolio may include some purchases: long-term, short-term, capacity Restructured (retail access or dereg) states Own T and D; do not own G (although may be in affiliated company) Customers may buy a “standard offer” G from the utility but others may provide as well LDC: may own some storage capability, some pipeline

21. 21 Investor-owned Utilities (IOUs) In 2008: 239 electric IOUs, some of which are both gas and electric 360 gas distribution company IOUs Some of these are in holding companies that own more than one of the 239 IOUs Serve about 75% of the nation’s electric load Own about 75% of the nation’s generation and transmission Own about 2/3rds of the miles of gas pipeline Natural gas interstate pipeline companies are also investor-owned For more information, see www.eei.org and www.aga.org

22. 22 Publicly-Owned/Consumer-Owned Utilities (POUs and COUs) Municipal, public utility district, rural electric co-operative, other agencies (e.g. Salt River Project) Finance their capital needs from public debt markets Often able to get tax-free financing (lenders pay no taxes on interest payments) Commonly must carry substantial financial reserves to meet lending commitments; rates must fund this reserve as well as current costs and depreciation May or may not be vertically integrated – many get generation from IOUs or federal utilities; almost always provide a bundled product In general, the customers of a POU are its “shareholders” in the sense that the only source of payment for costs, including interest on and repayment of debt, are the customers; co-op customers may receive “dividends” In 2008, there were over 2000 municipal utilities and public utility districts and almost 1000 electric cooperatives; POUs serve about 15% of the US electric load and coops about 9% [add gas data] For more information, see www.appanet.org and www.nreca.org

23. 23 Federal Federal power marketing agencies Electric only Examples: Western Area Power Marketing Agency (WAPA), Bonneville Power Administration (BPA) Market power from facilities other branches of government operate Not-for-profit utilities often have “preference” to this power May own and operate transmission Generally wholesale only but may have limited number of retail/direct customers (about 1%) Tennessee Valley Authority (TVA) Both owns resources and markets them at wholesale

24. 24 The business model Both IOUs and POUs/COUs operate on the same business model: Revenues come from the sale of electricity or natural gas services, typically measured by kWh or therms flowing through a given meter Prices are based on cost of service The business model is important to both because it is how they must convey to debt and equity investors that sufficient cash will exist to provide a return or interest on the capital provided and, in the case of debt, repay the principle Volatility of revenue or expense is costly to both types of utilities because of the greater demands the volatility causes for capital and the uncertainty of return/interest and repayment that investors must consider IOU equity owners absorb some costs of service Except in extreme circumstances, the customers of a POU pay (now or later) for all of the costs of service of that utility. On rare occasions, POUs will default on bonds, shifting some costs to bondholders. The long-term consequences of this for the POU are severe, however, as it may face difficulty in borrowing funds for many years thereafter.Except in extreme circumstances, the customers of a POU pay (now or later) for all of the costs of service of that utility. On rare occasions, POUs will default on bonds, shifting some costs to bondholders. The long-term consequences of this for the POU are severe, however, as it may face difficulty in borrowing funds for many years thereafter.

25. 25 The business model The industry adopted a monopoly model at turn of 20th century because of economies of scale This was particularly the case with generation and ability to serve diverse loads with one set of generating resources Also important to avoid mess and waste of multiple local distribution systems; this was the primary driver for LDCs Economies of scale for size of generation peaked in 1950s; smaller units can now match thermal efficiency and provide other value What about other economies of scale? Studies in the 1990s showed that economies of scale for utilities rise rapidly to a size of about 50,000 and then level off Many POUs are smaller than this By far the best source I have found for learning about the early days and economics of the industry is “The Electric City, “ by Harold Platt. This is the story of Commonwealth Edison (in Chicago), the utility Smauel Insull came to run in the late 1800s. It was Insull who realized that he should price electricity differently based on when someone was using it and for what (he charged far more for lighting than trolleys) and that all would benefit from sharing the same generating resource over the greatest possible load. He formed a blue-ribbon commission to write a model law for regulation of utilities at the state level and this became the core of what New York and Wisconsin adopted. By far the best source I have found for learning about the early days and economics of the industry is “The Electric City, “ by Harold Platt. This is the story of Commonwealth Edison (in Chicago), the utility Smauel Insull came to run in the late 1800s. It was Insull who realized that he should price electricity differently based on when someone was using it and for what (he charged far more for lighting than trolleys) and that all would benefit from sharing the same generating resource over the greatest possible load. He formed a blue-ribbon commission to write a model law for regulation of utilities at the state level and this became the core of what New York and Wisconsin adopted.

26. Utility Regulation

27. 27 Who regulates what Federal Energy Regulatory Commission Access to transmission and rates and terms of conditions for transmission service Wholesale power rates, including granting/revoking authority to a seller to sell at market-based rates and related regulation of wholesale markets Reliability Hydro-electric facility siting and licensing Lliquified natural gas (LNG) terminal licensing: this is in dispute in some parts of the country Natural gas pipeline siting and ratemaking Oversight of BPA’s rates POUs may have a separate governing board or, in the case of a municipal, the City Council may fill that function

28. 28 Who regulates what State public utility commissions: Retail rates of IOUs: vertically-integrated, T&D, and LDC Numerous other actions/decisions by IOUs Terms and conditions of service, e.g., credit requirements, cut-offs Financings Mergers Affiliated interest contracts Property sales Safety and reliability In some states, this includes POUs and COUs Some states also regulate co-op rates

29. 29 The Regulatory Compact for IOUs Customers Get Right to safe and reliable service Efficient investment and operation At rates set to prevent high, monopolistic level profits Customers Give Pay Bills @ PUC-set rates No alternative supplier IOUs Get A franchised monopoly service territory Opportunity to cover costs including “fair and reasonable” return Long-run protection from loss IOUs Give Obligation to serve At Commission-set Prices No opportunity for long-run excess profit

30. 30 General IOU Ratemaking Process Utility typically initiates with proposed new rates and written testimony supporting them Commission suspends proposed new rates for investigation (some states allow an interim increase subject to refund) Parties (including Commission Staff) intervene and ask questions; all parties file additional written testimony Partial or total settlements occur Non-settled issues go to hearing; parties brief the Commission on the issues Commission issues an order deciding the case and authorizing the utility to file new tariffs in accordance with decision This can take as little as 45 days and as long as a year or more Some utilities file new rates on a set schedule; others only as needed

31. 31 Rate Cases Rate cases tend to have two very distinct sets of issues What is the utility’s cost of service or revenue requirement How should customers pay those costs of service Sometimes Commissions will actually separate these issues into two phases of a case

32. 32 Cost of Service Costs must be prudently incurred Based on what is known or knowable at the time of the decision Increasingly a matter of documentation Cost-based ratemaking formula is: + operations and maintenance expense + depreciation ± amortization + taxes + (rate of return)(rate base – acc. dep.) ____________________ revenue requirement

33. 33 Test Year Utility rates generally changed on basis of results in a test year Many commissions use a historic test year Actual costs, adjusted for known and measurable future changes and removal of any unusual items or imprudent costs in the actual year chosen Actual revenues, adjusted to “normal” weather Good for utility in times when productivity rising faster than inflation and investment needs and/or when sales are rising Some commissions use a future test year, usually starting about the time the new rates are expected to take effect Forecasted costs, usually based on a budget escalated to the future but often compared to historical trends Forecasted load Good for utility in times when inflation and investment needs are increasing and/or when sales are falling

34. 34 Revenue Requirements O&M includes such items as fuel and purchased power, administrative and general, and customer service Where most labor dollars go, although some are allocated to capital Depreciation is the spreading of the cost of physical plant over a useful economic life Plant in rate base is at original cost less depreciation Amortization is the equivalent for intangible assets or liabilities, with a Commission-chosen “life” Taxes Federal and state income Property Labor-related O&M can be both “fixed” and “variable.” These terms refer to the nature of the cost rather than its accounting designation. Thus, variable costs are those that change in close relationship with customer use of electricity. Fixed costs are those that do not, although they may well change based on inflation, number of customer accounts, interests rates or other factors. Fuel and purchased power are operation expenses in accounting terms and this is where they will appear on a utility’s income statement and in the FERC Accounts. O&M can be both “fixed” and “variable.” These terms refer to the nature of the cost rather than its accounting designation. Thus, variable costs are those that change in close relationship with customer use of electricity. Fixed costs are those that do not, although they may well change based on inflation, number of customer accounts, interests rates or other factors. Fuel and purchased power are operation expenses in accounting terms and this is where they will appear on a utility’s income statement and in the FERC Accounts.

35. 35 Rate of Return Costs of debt, preferred stock (if any), and common equity, weighted by the amount of capital the utility has in each form The amount of capital in each form is called capital structure A common capital structure is between 45-55% debt and, conversely, 55-45% equity Equity is the most expensive capital but the less equity in the capital structure, typically the more that utility must pay to borrow money An ideal capital structure balances the higher cost of equity with the interest rate savings from a larger proportion of equity Commissions Generally use the actual cost of debt and preferred stock Must set the return on common equity because this is not a known number Methodologies: CAPM, DCF Smell test: returns recently granted other utilities Return on common equity is “profit” and the percentage is typically expressed net of income taxes Here is a sample cost of capital calculation: Type of Capital Cost % of Capital Structure Weighted Cost Debt 8% 44% 3.52% Preferred Stock 10% 2% 0.2% Common stock 11% 44% 4.84% 100% 8.56% This is the after-tax cost of capital. Sometimes you will also see a number before-tax or “grossed up for taxes. This occurs because the cost of common stock is actually income to the utility and taxable. Taxes are a recognizable cost of service. Thus, revenue requirement will include an estimate of taxes due based on the income the utility would earn if everything went as in the test year.Here is a sample cost of capital calculation: Type of Capital Cost % of Capital Structure Weighted Cost Debt 8% 44% 3.52% Preferred Stock 10% 2% 0.2% Common stock 11% 44% 4.84% 100% 8.56% This is the after-tax cost of capital. Sometimes you will also see a number before-tax or “grossed up for taxes. This occurs because the cost of common stock is actually income to the utility and taxable. Taxes are a recognizable cost of service. Thus, revenue requirement will include an estimate of taxes due based on the income the utility would earn if everything went as in the test year.

36. 36 Rate Base Rate base is the amount invested in property used and useful for utility service Used and useful standard has been applied in the past to disallow costs of generating plants brought on-line at a time of surplus Generally does not apply to utility plant that is temporarily out of service Property is included in rate base at original cost Each year, the amount allowed as depreciation expense reduces rate base The utility earns a return or profit only on the amount not yet depreciated This return is highest when plant first enters service; this is why people call cost of service ratemaking “front-end loaded” In the long run, unless rate base grows, profit cannot grow If a utility is not engaged in a major capital program and is simply replacing equipment as it wears out (e.g. distribution poles), the amount it invests in any given year may be equal to or less than the amount it depreciates in that year and, thus, the capital recovery assumptions from its last rate case would remain generally right. This is never the case, however, with a major generating plant. By their nature, these are known as “lumpy” investments. People call them “front-end loaded” because, in the first year that the utility includes the plant in its revenue requirement the amount of investment on which it may recover its cost of capital is as high as it likely ever will be (barring a major capital addition down the road). For example, assume it is a $1 billion plant, with a 50 year life, for which the Commission decides to use straight-line depreciation (the same amount every year) . Revenue requirement for its first year must include $20 million in depreciation and a return to the utility on $980 million, as well as operation and maintenance expense (including fuel) for the plant. Every year (again, without regard to capital additions), the utility will depreciate another $20 million. Although one would expect O&M to rise over time, historically for most plants it has not risen faster than depreciation has caused the capital cost recovery to fall. Thus, depending on what is happening with fuel, the plant gets cheaper and cheaper to operate every year. The nature of “rate of return” or “cost of service” regulation is such that a utility’s only long-term income opportunity is to invest in plant that is “used and useful” for utility service. Thus, purchasing power or helping customers use less electricity (when the utility expenses the costs of incentives and program administration) causes a “lost opportunity.” Purchasing power is particularly troublesome because some of the credit/debt rating agencies consider purchase power obligations to be the functional equivalent of debt and rate the utility’s debt accordingly, potentially causing the cost of debt to rise. If the utility operates in a state that does not allow automatic pass-through of purchased power costs, the utility may also be exposed to cost fluctuations that mean it bears risk with respect to the purchased power, not unlike the risk on a plant, but it has no return opportunity. A few regulators have recognized this problem and allowed some earnings opportunity in connection with purchased power but it is extremely rare.If a utility is not engaged in a major capital program and is simply replacing equipment as it wears out (e.g. distribution poles), the amount it invests in any given year may be equal to or less than the amount it depreciates in that year and, thus, the capital recovery assumptions from its last rate case would remain generally right. This is never the case, however, with a major generating plant. By their nature, these are known as “lumpy” investments. People call them “front-end loaded” because, in the first year that the utility includes the plant in its revenue requirement the amount of investment on which it may recover its cost of capital is as high as it likely ever will be (barring a major capital addition down the road). For example, assume it is a $1 billion plant, with a 50 year life, for which the Commission decides to use straight-line depreciation (the same amount every year) . Revenue requirement for its first year must include $20 million in depreciation and a return to the utility on $980 million, as well as operation and maintenance expense (including fuel) for the plant. Every year (again, without regard to capital additions), the utility will depreciate another $20 million. Although one would expect O&M to rise over time, historically for most plants it has not risen faster than depreciation has caused the capital cost recovery to fall. Thus, depending on what is happening with fuel, the plant gets cheaper and cheaper to operate every year. The nature of “rate of return” or “cost of service” regulation is such that a utility’s only long-term income opportunity is to invest in plant that is “used and useful” for utility service. Thus, purchasing power or helping customers use less electricity (when the utility expenses the costs of incentives and program administration) causes a “lost opportunity.” Purchasing power is particularly troublesome because some of the credit/debt rating agencies consider purchase power obligations to be the functional equivalent of debt and rate the utility’s debt accordingly, potentially causing the cost of debt to rise. If the utility operates in a state that does not allow automatic pass-through of purchased power costs, the utility may also be exposed to cost fluctuations that mean it bears risk with respect to the purchased power, not unlike the risk on a plant, but it has no return opportunity. A few regulators have recognized this problem and allowed some earnings opportunity in connection with purchased power but it is extremely rare.

37. 37 Fuel and Purchased Power Virtually all LDCs recover the amount they spend on gas supply dollar for dollar from customers Estimate included in rates on a prior basis True-up passes amounts over or under estimate through to customers Often called a purchased gas adjustment (PGA) clause Most IOU electric utilities recover the amount they spend on fuel (coal, oil, natural gas) and purchased power (net of wholesale sales) Some commissions require a sharing of amounts over or under the amount included in the last test year; e.g., 90-10 Some commissions set the amount included in rates more frequently than a general rate case; e.g. annually or quarterly Often called a fuel cost adjustment clause (FAC) or power cost adjustment clause (PCA) If an electric utility has a 100% pass-though of fuel and net interchange (power purchases and sales), decoupling for them has the same issues that decoupling for a gas utility does, albeit with more dollars at stake because the electric utility will have fixed costs in generation as well as distribution. If the electric utility does not have a 100% pass-through, then decoupling can be more complicated because the utility may recover some percentage of lost retail sales margin through wholesale sales, if it is in a position to make any. This is solvable but requires some attention.If an electric utility has a 100% pass-though of fuel and net interchange (power purchases and sales), decoupling for them has the same issues that decoupling for a gas utility does, albeit with more dollars at stake because the electric utility will have fixed costs in generation as well as distribution. If the electric utility does not have a 100% pass-through, then decoupling can be more complicated because the utility may recover some percentage of lost retail sales margin through wholesale sales, if it is in a position to make any. This is solvable but requires some attention.

38. 38 Other Adjustment Clauses Tradition of cost of service ratemaking is that regulator must consider all changes in revenue and expense at one time, setting new rates only in a general rate case Fuel and purchased power adjustments were the first exception Other exceptions have followed, such as: Environmental compliance costs Natural gas pipe replacements Storm repair and tree-trimming costs Renewable resource investments or purchases under an RPS Some jurisdictions call these “trackers;” the common feature is that regulators focus only on changes in the specified cost or revenue categories An adjustment clause often appears in a tariff “rider”. This is a tariff that states an adjustment applicable to more than one rate schedule. Thus, a purchased gas rider will probably apply to all of the gas utility’s sales schedules and a fuel adjustment clause would apply to all of an electric utilities sales schedules. Other riders may apply to a subset of sales schedules.An adjustment clause often appears in a tariff “rider”. This is a tariff that states an adjustment applicable to more than one rate schedule. Thus, a purchased gas rider will probably apply to all of the gas utility’s sales schedules and a fuel adjustment clause would apply to all of an electric utilities sales schedules. Other riders may apply to a subset of sales schedules.

39. 39 The nature of the process Common for initial utility request to be much larger than amount finally reached in settlement or by Commission order; reasons include: Final ROE lower Disallowance of some expenses Disputes over “right” assumptions for other expenses Non-earnings adjustments, such as depreciation rates, amortization periods Excellent commentary in recent essay by Scott Hempling: Low Rates, High Rates, Wrong Rates, Right Rates (January 2009); he asks two critical questions: Have we allowed this “consumer protection” purpose to transmogrify, from protection against monopoly inefficiency to protection against high costs in general? Are we seeking “low rates,” rather than “right rates?”

40. 40 Turning revenue requirement into rates Rates = Revenue Requirement Sales Revenues = Sales x Rates Actual revenues will always differ from ratemaking revenues Weather Economic drivers Other reasons

41. 41 Rate Spread Rate spread is the process of allocating the revenue requirement across a utility’s various tariffs Utilities and commissions use cost of service (COS) studies to do this Calculate using direct assignment and allocation what it costs to serve one customer on a given rate schedule Many use embedded (utility’s actual historic) costs for this purpose and spread the rate change according to the results Some use marginal costs – what it would cost to serve a customer of this type if the utility was incurring all of the costs today This makes the most difference for generation costs Rate spread then is done to have each customer class recover an equal percentage of its marginal costs

42. 42 Rate Design Rate design is the process of allocating the revenue requirement assigned to a particular tariff among the various elements in that tariff, often called billing determinants Most rates include a fixed customer charge that applies per billing cycle Virtually all rates include a variable commodity (kWh or therm) rate that applies to the measured use in a given billing cycle Inverted: rate increases the more a customer uses; e.g., California electric IOUs Declining: rate decreases the more a customer uses; e.g. For larger customers, may include A fixed facilities charge, based on additional distribution costs, applied per billing period A variable demand charge, based on the peak amount used during during a billing period) Time-of-day or on-peak and off-peak rates are common for larger commercial and industrial customers but less common for residential and small commercial

43. 43 Common rates Utilities typically have different rates for Residential customers Small commercial customers Larger commercial customers Industrial customers Street-lighting Standby power (for customers with their own generation) Utilities may have rates for “Green” power Time-of-use Irrigation pumping Net metering Direct access (electric) or transportation service (gas)

44. 44 Sample rate designPGE residential service MONTHLY RATE The sum of the following charges per Point of Delivery (POD)*: Basic Charge Single Phase Service $10.00 Three Phase Service $13.00 Transmission and Related Services Charge 0.212 ¢ per kWh Distribution Charge 2.897 ¢ per kWh Energy Charge Standard Service First 250 kWh 5.124 ¢ per kWh Over 250 kWh 6.899 ¢ per kWh Time-of-Use (TOU) Portfolio Option (enrollment is necessary) On-Peak Period 12.155 ¢ per kWh Mid-Peak Period 6.899 ¢ per kWh Off-Peak Period 4.052 ¢ per kWh First 250 kWh block adjustment (1.775) ¢ per kWh Nonstandard Metering Charge (applicable to TOU) Single Phase meter $1.00 Three Phase meter $4.25 * See Schedule 100 for applicable adjustments

45. 45 Sample rate designPGE large commercial service The sum of the following charges at the applicable Delivery Voltage per Point of Delivery (POD)*: Delivery Voltage Secondary Primary Basic Charge Single Phase Service $20.00 Three Phase Service $25.00 $80.00 Transmission and Related Services Charge per kW of monthly Demand $0.70 $0.70 Distribution Charges** The sum of the following: per kW of Facility Capacity First 30 kW $1.48 $1.46 Over 30 kW $2.15 $1.46 per kW of monthly Demand $1.97 $1.97 Energy Charge Cost of Service Option per kWh 6.363 ¢ 6.153 ¢ See below for Daily or Monthly Pricing Option descriptions. System Usage Charge per kWh 0.406 ¢ 0.391 ¢ * See Schedule 100 for applicable adjustments. ** The Company may require a Customer with dedicated substation capacity and/or redundant distribution facilities to execute a written agreement specifying a higher minimum monthly Facility Capacity and monthly Demand for the applicable POD.

46. 46 Rates Designing rates is an art, not a science Rates are “cost-based” only in a general sense; common cross-subsidies exist: Between different geographic areas: urban versus rural Between “levels” of service: downtown network versus radial system Between customers who began service at a time when embedded costs of generation were lower than current marginal cost of generation (vintaging) Between some customers who use electricity at different times Between some customers who have larger gaps between average use and peak use Between customers who make more of less use of customer service or credit services For most of the first 50 years of electric utility service, the usually-true assumption was that adding another customer or a current customer adding more electrical use was good for all customers. With economies of scale in generation and often through the transmission and distribution system, the added customer or load simply absorbed fixed costs previously allocated to existing customers. This changed when we exhausted economies of scale in generation and technological progress failed to keep up with rising costs. The gap between the embedded cost of generation in current rates and the marginal cost of new generation (not melded in with the old, but stand-alone) grew. Ratemaking does not distinguish between when a customer came on the system; occasionally, it distinguishes between customers at different sizes of load (e.g., through tiered rate structures such as California has). But, generally speaking, all customers must absorb the additional costs caused by the new customers or new load. This generally overlooked point is a counter to the argument that customers not participating in energy efficiency programs are subsidizing those who are. As long as the marginal cost of electricity (particularly counting all external costs) is higher than the embedded cost in rates, the reverse is true: savings customers are helping everyone and new/growing customers are causing costs to rise.For most of the first 50 years of electric utility service, the usually-true assumption was that adding another customer or a current customer adding more electrical use was good for all customers. With economies of scale in generation and often through the transmission and distribution system, the added customer or load simply absorbed fixed costs previously allocated to existing customers. This changed when we exhausted economies of scale in generation and technological progress failed to keep up with rising costs. The gap between the embedded cost of generation in current rates and the marginal cost of new generation (not melded in with the old, but stand-alone) grew. Ratemaking does not distinguish between when a customer came on the system; occasionally, it distinguishes between customers at different sizes of load (e.g., through tiered rate structures such as California has). But, generally speaking, all customers must absorb the additional costs caused by the new customers or new load. This generally overlooked point is a counter to the argument that customers not participating in energy efficiency programs are subsidizing those who are. As long as the marginal cost of electricity (particularly counting all external costs) is higher than the embedded cost in rates, the reverse is true: savings customers are helping everyone and new/growing customers are causing costs to rise.

47. 47 POU Ratemaking Much of the process – and controversy – is the same Size of O&M Workforce and compensation Size of capital program Size of reserves to carry once they meet minimum requirements Expected loads Rate spread and rate design Political power of residential customers Political power of industrial customers POUs do not have a return on equity but municipal utilities in particular may have obligations to a provide revenue (directly or indirectly) to their city government, pitting utility ratepayers against city taxpayers

48. 48 Decoupling Decoupling means that utility – IOU or POU – revenues will not vary depending on kWh sales (billing determinants) Two primary methods Straight fixed-variable rate design Accounting/regulatory mechanism Utility books revenue Based on last approved revenue requirement, possibly adjusted by inflation Based on number of customer accounts and fixed costs per account Decoupling is easy for gas LDCs; it can be more complicated for electric if the utility does not true-up all variable energy costs See note about decoupling on slide 37.See note about decoupling on slide 37.

49. 49 Notes for Advocates A general rate case includes a review of the utility’s entire tariff, including rules and policies (e.g., line extension policy) that may need review because many date to when the primary goal was selling electricity or gas A general rate case often covers many detailed issues beyond the scope of energy efficiency/environmental advocacy Often wise to limit participation to a few issues of highest concern Sometimes issues can be put on a separate track; e.g., energy efficiency funding, or decoupling It may be worthwhile to support utility requests for increases in customer service expense that relate to non-programmatic energy efficiency efforts and customer intelligence (surveying etc.) Over the last 15 years or so, many utilities dramatically reduced RD&D; this area may also warrant support, particularly for demonstration programs related to efficiency and customer-sided renewable resources Depreciation can be a key decision – it is partly the long depreciation lives assigned most thermal generating resources that make them look so inexpensive; utilities often present new depreciation studies along with general rate case filings

50. Electric Utility Policies

51. 51 Integrated Resource Planning (IRP) Many IOUs that remain vertically integrated prepare resource plans covering 20+ years into the future Some POUs also prepare such plans In the NW, the Northwest Power Planning and Conservation Council prepares a plan for the region every five years Plans that include demand-side as well as supply-side resources, are known as integrated resource plans IOU plans may involve public process, Commission process, and Commission action, such as approval or acknowledgement (less than approval) Actual procurement may or may not link back to these plans Advocates often need to participate both in planning and review of actual procurement processes

52. 52 IRP Planning starts with a load forecast Load forecasts are a combination of economic forecasts and recently observed relationships between various types of economic and/or demographic data and electricity consumption Both load forecasts and economic forecasts, notwithstanding considerable complexity in modeling and a vast number of inputs both factual and assumptions, generally accomplish little more than extending the most recent trends into the future All forecasts will be “right” only if nothing changes Demand-side options have the potential to significantly reduce, but don’t always eliminate, forecasted growth

53. 53 IRP Demand-side options, such as energy efficiency, customer-sided distributed generation, and demand response are typically estimated in a separate analysis that applies the Total Resource Cost test to compare costs to benefits of various measures, programs, or aggregate programs by sector The highest number will be the technical potential; typically, this assumes replacement of existing structures, equipment and appliances only at end-of-life Planners will usually reduce the technical potential to economic potential, to reflect that some measures may not be cost-effective at that end-of-life point A further reduction produces the “achievable potential,” which add program, administrative and training costs to the demand-side resources and the effects of “real-world” constraints Advocacy should focus on energy efficiency potential Energy efficiency potential is entirely dependent on the input assumptions made and these can vary widely May want to urge an independent energy efficiency potential study

54. 54 IRP Bulk of the plan is options for filling any gap between the load expected and the resources currently available, including how those resources may change over the period Assuming the utility needs new resources, the goal is to choose a set of resources that will have the “best” cost at the “best” risk over time Using assumptions, utilities compare the expected costs of various resource choices over time Using other studies, utilities look at the risk that things could work out differently than expected; often this includes scenarios As an advocate, it is critical to understand these assumptions Usually includes an Action Plan, detailing what the utility intends to do over the next 2-3 years, before the next planning cycle Typically utilities apply a “discount rate” to the future stream of costs to obtain the net present value of various choices today and compare those single figures. Choosing this discount rate can be highly controversial. Utilities often use a rate that is quite high (9-10%); environmental groups often argue for a “societal” rate that is much lower (2%). Generally speaking, the higher the discount rate , the less meaningful dollars in the future will be in any comparison. It is not even clear that the same discount rate should apply to all costs that are included, from future O&M to externalities. Moreover, this practice glosses over what can be very real timing differences in the costs of various resources; e.g., a power purchase may have a slow, steady increase in cost while a new coal generating plant will have a front-end loaded shape.Typically utilities apply a “discount rate” to the future stream of costs to obtain the net present value of various choices today and compare those single figures. Choosing this discount rate can be highly controversial. Utilities often use a rate that is quite high (9-10%); environmental groups often argue for a “societal” rate that is much lower (2%). Generally speaking, the higher the discount rate , the less meaningful dollars in the future will be in any comparison. It is not even clear that the same discount rate should apply to all costs that are included, from future O&M to externalities. Moreover, this practice glosses over what can be very real timing differences in the costs of various resources; e.g., a power purchase may have a slow, steady increase in cost while a new coal generating plant will have a front-end loaded shape.

55. 55 Industry Restructuring:Wholesale In 1980s, federal action to deregulate natural gas production and require interstate pipelines to sell transportation service unbundled from gas sales In early 1990s, federal action to: Enable third parties to use IOU transmission on an unbundled basis Deregulate independent (non-utility) generation and sale of electricity Independent power producers (IPPs) developed significant new generation in 1990s, mostly gas-fired Some IPPs purchased existing generation form utilities By mid-1990s, active markets for: Natural gas Power sales of various terms Capacity sales of various terms Derivatives Market participants trade for profit, cost mitigation, and risk management

56. 56 Wholesale market and transmission regulation Intense activity here since the 2000/01 Western power crisis On wholesale side, FERC has broad authority to regulate market behavior (not rates) and market power, including natural gas/electricity interplay On the transmission side: Functional separation permitted; standards of conduct apply Regional Transmission Organizations (e.g. PJM) preferred Operate all the transmission; design and administer tariffs Run real-time and day-ahead power markets Some regions have resisted: e.g. NW By mid-decade, heightened focus on reliability, with numerous requirements FERC able to impose significant penalties

57. 57 Industry Restructuring: Retail In the 1990s/early 2000s, 24 states restructured their electric industries to allow competition to provide retail customers with electricity supply Approaches varied Some allowed only business retail customers to choose Some required the sale of utility generation to third parties or its transfer at a specified valuation to corporations affiliated with the utility Many “froze” the price of the utility’s remaining “standard offer” electricity product; as these freezes have expired, some retail customers have faced price increases of 50% or higher www.eia.doe.gov/cneaf/electricity/page/restructuring/restructure_elect.html maps state activity on restructuring

58. 58 Current status of competition Wholesale competition IPP development of generation has slowed FERC has added numerous market regulations since 2000 Retail competition 16 states continue to offer full retail access 8 states have suspended – partially or totally Some are considering whether to retain and have recently allowed utilities to begin acquiring generation again (see, e.g., Ohio, Michigan, Illinois) – a partial return to vertical integration California currently considering whether to resume Few expect additional states to restructure anytime soon In general, restructured states follow the same trends as non-restructured states; it is simply much more complicated to develop and implement initiatives in restructured states

59. 59 Public Purpose Charges (PPC) Many states that restructured established public purpose charges (a certain amount on every customer bill, often as a percentage of the amount due), to ensure that progress on energy efficiency, renewable resource development, and RD&D continued after restructuring In some states, the regulated T&D utility remains responsible for the money and related actions; in other states, one or more government or non-profit organizations have the money and responsibility In most cases, the amounts chosen in the early 2000s (often based on expenditures then) are not sufficient for all cost-effective energy efficiency given the changes in underlying electricity costs

60. 60 Public Benefit Funds for Renewables(Estimated Funding) We should include a map for energy efficiency too. I know there is one similar to this, but I have to look for it since I can’t remember right now who put it out. Also, the data on CA is not really accurate since the PGC sunsets at the end of 2011 and the amount, I though, was more like $135 million/year. Perhaps they have combined other programs like the solar rooftop program.We should include a map for energy efficiency too. I know there is one similar to this, but I have to look for it since I can’t remember right now who put it out. Also, the data on CA is not really accurate since the PGC sunsets at the end of 2011 and the amount, I though, was more like $135 million/year. Perhaps they have combined other programs like the solar rooftop program.

61. 61 Renewable Portfolio Standards (RPS) As of 2008, 27 states have renewable portfolio standard requirements; several others have goals Under these requirements (typically state statute), utilities (often just IOUs but sometimes all) must acquire renewable resources or renewable resource attributes (green tags) at certain percentages of their system load by certain deadlines RPS statutes often cover: What qualifies (type, location, restrictions on green tags) Cost caps or safety valves to preclude too large an effect on retail rates Cost recovery guarantees for utilities (assuming prudence) Penalties for failure to meet the standard A looming issue is whether there will be a federal RPS (as has been introduced in Congress) and, if so, whether it will pre-empt or backstop/supplement the state standards that exist Some states have also adopted Energy Efficiency Portfolio Standards (EEPS), setting goals for the amount of load reductions utilities will achieve through energy efficiency (e.g., Minnesota, Ohio, Illinois) We should also do a slide for energy efficiency standards too. Again, I know I’ve seen a similar map, just have to find it..We should also do a slide for energy efficiency standards too. Again, I know I’ve seen a similar map, just have to find it..

62. 62

63. 63 Current Issues in Renewables Congress recently extended tax credits, which will help continue to spur development (solar is for 8 years!) Wind is considered largely mature at this point; installation will grow significantly where the resource is good but costs likely to rise over time driven by underlying costs of materials Solar could experience significant cost declines; numerous competing technologies and much experimentation in materials Geothermal also has promise: more resource than thought, possibly lower cost than early ones Biomass coming along but fuel, fuel transportation, and fuel conversion efficiency and sustainability issues will make it less attractive than some other renewable resources Tidal, wave, fuel cells are a ways out Integration of intermittent renewables and transmission planning and siting are among the most critical issues for renewables today

64. 64 Energy Efficiency Portfolio Standards Legislative WA: All cost-effective NV: in RPS, up to 25% of 20% RPS rqmt CO: cum. 11.5% by 2020 NM: 5% by 2014, 10% by 2020 TX: 20% of load growth by 2010 (demand) MN: 1.5% per year ILL: 2%/year by 2015 and thereafter MI: 1% per year by 2012 and thereafter OH: 22% (energy) by 2025; 0.75% (peak) each year after 2009 NC: combined with RPS; no more than 40% of 12.5% in 2021 Legislative con’d MD: 15% by 2015 CN: 1.5% per year PA: 3% by 2013; PUC targets thereafter VA: 10% by 2022 Regulatory CA: about 1%/year through 2013 NJ: year by year goals; evaluating 20% by 2020 OR: year by year goals for ETC NY: 15% by 2015 (Governor) VT: year by year for Efficiency Vermont

65. 65 Other Current Issues Carbon caps, taxes, allowances, trading Carbon capture and sequestration Water constraints Nuclear costs Electric vehicles – hybrid and pure Smart Grid, smart infrastructure Transmission for renewable resources Distributed generation

66. 66 Good Sources of Information http://www.eia.doe.gov/: this is the Energy Information Administration website. It has lots of good, basic information and statistics about energy http://www.epa.gov/cleanenergy/energy-programs/napee/index.html: this will direct you to the National Action Plan for Energy Efficiency, a good source on the latest, mainstream thinking about energy efficiency http://www.mckinsey.com/clientservice/ccsi/thinking.asp: this link takes you to a variety of McKinsey publications about climate change and the costs/benefits of addressing it, including the study (November 2007) regarding a path by which the US could reduce substantial reduction at no net cost by tapping available energy efficiency http://www.dsireusa.org/index.cfm?EE=0&RE=1: this website comprehensively covers requirements and incentives for energy efficiency and renewable resources for all states and federally http://apps1.eere.energy.gov/states/: this site has great information about how each of the states uses energy, including natural gas and electricity, with handy ways to compare states on different bases http://www.energy.ca.gov/energy_action_plan/2003-05-08_ACTION_PLAN.PDF and http://www.energy.ca.gov/energy_action_plan/2005-09-21_EAP2_FINAL.PDF are the California Energy Action Plans