Energy Basics by mikeholy


									An Introduction to Energy,
Electricity and Utility

Energy Efficiency Advocacy Training
Energy, Electricity, and
Natural Gas Basics
    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

    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
            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

    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

    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

       Common conversions
          1 kWh = 3,412 btu (british thermal unit)
          1 cubic foot natural gas = 1,028 btu
          1 therm = 100,000 btu

    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
    Electricity Systems

       The meter is a billing device, not a border to the physical
       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

    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

           Where electricity comes from in the US

     Figure ES 1. US Electric Power Industry Net Generation, 2007

     How we use electricity

        We use electricity primarily in structures; exceptions include:
             Pumps
             Streetlights, traffic signals
             Other distributed equipment, e.g., telecommunications relay
        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

     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

     How we use electricity

        Across the type of structures, the (2007) distribution of use
             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

     Electricity Price History

     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
            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
        Delivery losses:
            T&D losses in the US average 7.2%
            An individual transformer loses up to 2% in the transformation
        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
     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

     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
             Purchases tend to be near-term: a season (6-month strip) to 1-2 years
             Credit requirements prevent many longer-term deals
        Flexibility in the system: storage
             Almost 400 active storage sites (depleted fields, aquifers,
              salt fields)
         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
Utility Basics
     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
     Investor-owned Utilities (IOUs)

        In 2008:
           239 electric IOUs, some of which are both gas and
           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
           Own about 2/3rds of the miles of gas pipeline
        Natural gas interstate pipeline companies are also investor-
        For more information, see and

     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
             Commonly must carry substantial financial reserves to meet lending
              commitments; rates must fund this reserve as well as current costs and
        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
        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 and


        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
           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

     The business model

        Both IOUs and POUs/COUs operate on the same business
             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

     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
           Also important to avoid mess and waste of multiple local
            distribution systems; this was the primary driver for
        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
Utility Regulation
     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

     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

              The Regulatory Compact for IOUs

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

                PUC Enforces Both Sides of the Compact
     General IOU Ratemaking
        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

     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

     Cost of Service

        Costs must be prudently incurred
           Based on what is known or knowable at the time of the
             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

     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

     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

     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
              • 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

     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
             This return is highest when plant first enters service; this is
              why people call cost of service ratemaking “front-end
        In the long run, unless rate base grows, profit cannot grow

     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
             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
             Often called a fuel cost adjustment clause (FAC)
              or power cost adjustment clause (PCA)

     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
        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

     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
             Final ROE lower
             Disallowance of some expenses
             Disputes over “right” assumptions for other expenses
             Non-earnings adjustments, such as depreciation rates, amortization

        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?”

     Turning revenue requirement
     into rates

      Rates = Revenue Requirement
      Revenues = Sales x Rates

      Actual revenues will always differ from
       ratemaking revenues
          Weather
          Economic drivers
          Other reasons

     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
             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

     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
             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

     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

     Sample rate design
     PGE residential service
     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

     Sample rate design
     PGE 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.


        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
             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

     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
             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


        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

         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

Electric Utility Policies
     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


        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

        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

        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
        Usually includes an Action Plan, detailing what the utility
         intends to do over the next 2-3 years, before the next
         planning cycle

         Industry Restructuring:
        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
               • 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
     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

     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
         structure_elect.html maps state activity on

     Current status of competition
        Wholesale competition
             IPP development of generation has slowed
             FERC has added numerous market regulations since
        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
58       restructured states
     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

59                                                                                                                    March 2008

                       Public Benefit Funds for Renewables
                       (Estimated Funding)
                            MT: $750,000 in 2008                                          ME: 2008 funding TBD                    VT: $6.6M in 2008
                            $8.3M from 1999-2009           MN: $16M in 2008              $411,000 from 2002-2008                 $34M from 2004-2011
                                                         $264M from 1999-2017*
                                                                                                                                  MA: $25M in 2008
                                                                                 MI: $1.7M in 2008                              $525M from 1998-2017*
     OR: $12M in 2008                                                          $25M from 2001-2017*
                                                                                                                                  RI: $2.2M in 2008
  $182M from 2001-2017**
                                                                                                                                $38M from 1997-2017*
                                                            WI: $5.5M in 2008                   NY: $9.5M in 2008
                                                          $97M from 2001-2017*                $114M from 1999-2011                 CT: $24M in 2008
                                                                                                                                $435M from 2000-2017*
                                                                IL: $5.5M in 2008
                                                                                       OH: $3.2M in 2008                          NJ: $102M in 2008
                                                              $99M from 1998-2015
                                                                                      $63M from 2001-2010                       $637M from 2001-2012
    CA: $331M in 2008
  $4,149M from 1998-2016                                                                                                         PA: $950,000 in 2008
                                                                                                                                 $63M from 1999-2010
                                                                                                                                  DE: $3.5M in 2008
                                                                                                       D.C.: $400,000 in 2008
                                                                                                                                $49M from 1999-2017*
                                                                                                      $5.1M from 2004-2017*

                                                                                                                    16 State Funds + DC
                                                                                                                      ~$6.8 B by 2017

 * Fund does not have a specified expiration date.                                                                Funded by voluntary contributions

 ** The Oregon Energy Trust is scheduled to expire in 2025.
(NOTE: Slides 2-9 explain the methodology for calculating funding estimates.)

     Renewable Portfolio Standards
        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)
DSIRE:                                                                                                                                November 2008

                              Renewables Portfolio Standards

                                                                                                                                     ME: 30% by 2000
                                                                        MN: 25% by 2025              VT: (1) RE meets any            10% by 2017 - new RE
                                                                                                   increase in retail sales by
                                                                        (Xcel: 30% by 2020)
    *WA: 15% by 2020                                                                                 2012; (2) 20% by 2017             ☼ NH: 23.8% in 2025
                                                      ND: 10% by 2015
                                                                                 WI: requirement varies by                            ☼ MA: 15% by 2020 +
                                                                                  utility; 10% by 2015 goal                               1% annual increase
                                            MT: 15% by 2015                                                                              (Class I Renewables)
OR: 25% by 2025 (large utilities)
5% - 10% by 2025 (smaller utilities)                                                      MI: 10% by 2015                            RI: 16% by 2020
                                                            SD: 10% by 2015
                                                                                                                                    CT: 23% by 2020
              ☼ *NV: 20% by 2015                                                     ☼ OH: 25%** by 2025
                                           *UT: 20% by 2025        IA: 105 MW                                                    ☼ NY: 24% by 2013
                                                                                    IL: 25% by 2025                              ☼ NJ: 22.5% by 2021
                                          ☼ CO: 20% by 2020 (IOUs)
      CA: 20% by 2010                   *10% by 2020 (co-ops & large munis)
                                                                                                                                 ☼ PA: 18%** by 2020
                                                                                MO: 11% by 2020
                                                                                                                                 ☼ MD: 20% by 2022
                                                                                        ☼ NC: 12.5% by 2021 (IOUs)
                    ☼ AZ: 15% by 2025                                                    10% by 2018 (co-ops & munis)            ☼ *DE: 20% by 2019
                                                                                                                                 ☼ DC: 20% by 2020
                         ☼ NM: 20% by 2020 (IOUs)
                               10% by 2020 (co-ops)                                                                                *VA: 12% by 2022

                                                          TX: 5,880 MW by 2015                                                                                  State RPS

               HI: 20% by 2020                                                                                                                                  State Goal

                                                                                                                                                                Solar water
                                                                                                                                                                heating eligible
                                                   ☼ Minimum solar or customer-sited RE requirement
                                                      * Increased credit for solar or customer-sited RE
                                          **Includes separate tier of non-renewable “alternative” energy resources

     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

     Energy Efficiency Portfolio Standards

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

     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

     Good Sources of Information
     All associated documents posted to Sharepoint – right-click here

      this is the Energy Information Administration
         website. It has lots of good, basic information and statistics about energy
         this will direct you to the National Action Plan for Energy Efficiency, a good
         source on the latest, mainstream thinking about energy efficiency
      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
      this website
         comprehensively covers requirements and incentives for energy efficiency
         and renewable resources for all states and federally
      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
         08_ACTION_PLAN.PDF and
         21_EAP2_FINAL.PDF are the California Energy Action Plans

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