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Utility Issues And The Site Selection Process Webinar


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This presentation attempts to educate state, regional and local economic development allies on issues pertaining to electric and gas that impact the site selection process. It is intended to help economic developers to ask good questions of site selectors, which improves the process and makes their sites more competitive. Knowledge is power!

Published in: Business, Real Estate
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Utility Issues And The Site Selection Process Webinar

  1. 1. Utility Issues and the Site Selection Process <ul><li>Basic Training for our Economic Development Allies </li></ul>
  2. 2. Utilities – A Brief History The Early Days Independent Generators and Distributors Competition for customers A tangled web of power lines Read a detailed history at the Edison Electric Institute web site
  3. 3. Utilities – A Brief History <ul><li>Consolidation came in the 1920s </li></ul><ul><li>Large electric power holding companies were formed </li></ul><ul><li>By 1932, eight holding companies controlled 73% of U.S. investor-owned electric business </li></ul><ul><li>There was: </li></ul><ul><li>little effective state regulation </li></ul><ul><li>no federal regulation </li></ul><ul><li>holding companies overcharging subsidiaries </li></ul><ul><li>expenses being passed on to customers </li></ul><ul><li>What followed is known as “The Regulatory Compact” </li></ul><ul><li>Abuses were corrected with the passage of the 1935 Federal Power Act and the Public Utility Holding Company Act (PUHCA). </li></ul>
  4. 4. Utilities – A Brief History <ul><li>The Regulatory Compact </li></ul><ul><li>Is a covenant or contract between the authority of state governments, represented by public utility commissions (i.e. NYS Public Service Commission), the Federal Energy Regulatory Commission (FERC) and in some cases local governments and investor owned utility companies </li></ul><ul><li>In exchange for the obligation to provide service to all customers in a particular “territory”, investor owned electric utilities are given a territorial monopoly on service and allowed to earn a limited profit. State regulators have historically set prices at rates that reflect the cost of building power plants and putting up transmission and distribution systems (the wires). Profits have reflected the cost of capital. </li></ul><ul><li>This established the current structure of the industry. In addition to investor-owned utilities, public utilities and co-ops operate in this system. </li></ul>
  5. 5. Utility Regulation <ul><li>The FERC </li></ul><ul><ul><li>The Federal Energy Regulatory Commission regulates and oversees energy industries in the economic, environmental, and safety interests of the American public. FERC is the federal agency that regulates electricity transmission and wholesale electricity sales in interstate commerce.  FERC implements the laws of Congress through orders and rulemakings on electricity policy. For detailed information use this link </li></ul></ul>
  6. 6. Utility Regulation <ul><li>State Regulators </li></ul><ul><ul><li>Under State law, Public Service (or Utility) Commission members have the obligation to ensure the establishment and maintenance of utility services as may be required by the public convenience and necessity, and to ensure that such services are provided at rates and conditions that are just, reasonable and nondiscriminatory for all consumers </li></ul></ul><ul><ul><li>In New York State the regulator is the New York State Public Service Commission </li></ul></ul>
  7. 7. Utility Regulation <ul><li>Deregulation </li></ul><ul><ul><li>Is the elimination of some or all regulations from a previously regulated industry or sector of an industry. </li></ul></ul><ul><ul><li>In the 1990s the New York State Public Service Commission (PSC) opened the State's electric industry to competition. </li></ul></ul><ul><ul><li>Utilities divested their generation assets and a spot market for electricity was established. </li></ul></ul><ul><ul><li>Changes in the electric market allow customers to choose their supplier of electricity . Utilities deliver power to customers, under regulation by the NYS-PSC </li></ul></ul>
  8. 8. Utility Regulation <ul><li>Not all states have implemented deregulation </li></ul>
  9. 9. Utility Regulation <ul><li>Prior to deregulation the Utility operated as a vertically integrated, regulated monopoly that: </li></ul><ul><ul><li>Built and operated power plants </li></ul></ul><ul><ul><ul><li>(hydro-electric, nuclear, gas combined cycle, coal-fired) </li></ul></ul></ul><ul><ul><li>Transmitted energy over long distances </li></ul></ul><ul><ul><li> (transmission towers and wires) </li></ul></ul><ul><ul><li>Distributed energy to homes and businesses (electric poles and wires) </li></ul></ul><ul><ul><li>Provided ancillary services </li></ul></ul><ul><ul><li>(balancing of generation supply, managing the grid) </li></ul></ul><ul><ul><li>Provided metering, billing and customer services </li></ul></ul>
  10. 10. Utility Regulation <ul><li>After Restructuring </li></ul><ul><li>Unregulated Regulated </li></ul><ul><li>Independent Power Producers Energy Delivery Companies </li></ul>
  11. 11. Electric Delivery System
  12. 12. Overhead Electric Distribution System Overhead Transformer Primary Distribution Feeders Secondary Distribution Lines Telephone CATV
  13. 13. Basic Power Terms <ul><li>Amp = the number of electrons moving along a conductor path (flow) </li></ul><ul><li>Voltage = the ‘force’ at which energy flows (pressure) </li></ul><ul><li>Watt = one AMP at a pressure of one VOLT (Watts = Volts x Amps) </li></ul><ul><li>Kilowatt (kW) = 1,000 Watts </li></ul><ul><li>Megawatt (mW) = 1,000,000 Watts =1,000 kW </li></ul>
  14. 14. Basic Power Terms <ul><li>Demand = rate of energy consumption (kW) </li></ul><ul><li>Kilowatt Hour = quantity of energy (kWh) </li></ul><ul><li>Load Factor = the ratio of average load to peak load in a period </li></ul><ul><li>Power Factor = ratio of ‘true power’ to ‘total power </li></ul><ul><li>PF = kW </li></ul><ul><li> kVa </li></ul>
  15. 15. Information Needed for a Capacity Assessment and Rate Quote/Bill Estimate <ul><li>Basic Information Needed </li></ul><ul><ul><li>Site Location (address, intersection or map) </li></ul></ul><ul><ul><li>Peak Demand in Kilowatts (kW) </li></ul></ul><ul><ul><li>Energy Consumption in Kilowatt Hours (kWh) </li></ul></ul><ul><ul><li>Hours of Operation/Days per Week </li></ul></ul><ul><ul><li>Delivery Voltage at Site(s) </li></ul></ul><ul><ul><li>Distribution - Secondary @ 2.2 kV or Primary @ 13.2 kV </li></ul></ul><ul><ul><li>Transmission - Sub-transmission @ 34.5 kV or Transmission @ 69 kV, 115 kV </li></ul></ul>
  16. 16. Information Needed for Energy Intensive Operations <ul><li>MORE DETAILED INFORMATION </li></ul><ul><ul><li>Load Characteristics (type of operation) </li></ul></ul><ul><ul><li>Type of Equipment to be Used (motor sizes) </li></ul></ul><ul><ul><li>Power Quality Needs (is a dual feed required?) </li></ul></ul><ul><ul><li>Connected Load (kilovolt amperes - kVa) </li></ul></ul><ul><ul><li>Power Factor (PF = kW x kVa) </li></ul></ul>
  17. 17. Why does the Utility need this information? To Determine the Cost to Serve <ul><ul><li>Short Term </li></ul></ul><ul><ul><li>Determine Available Capacity and In-Service Date </li></ul></ul><ul><ul><li>Measure Impact on System </li></ul></ul><ul><ul><li>Snapshot of Demand on System </li></ul></ul><ul><ul><li>Plan for Growth </li></ul></ul><ul><li>Long Term </li></ul><ul><li>Determine Upstream Impact </li></ul><ul><li>Determine Downstream’ Impact </li></ul><ul><li>Anticipate System Demands </li></ul><ul><li>Make the best use of time </li></ul>
  18. 18. Why Bring Utility in on Retention/Expansion Opportunities? <ul><li>Determine if impending change will effect service </li></ul><ul><li> Manage Customer and Community Expectations </li></ul><ul><li>Review by engineers and planners </li></ul><ul><li>Manage Customer and Community Expectations </li></ul><ul><li>Determine best way to serve </li></ul><ul><li> Manage Customer and Community Expectations </li></ul><ul><li>Determine potential customer charges </li></ul><ul><li>Manage Expectations and Address with Programs </li></ul>
  19. 19. What is an “Electric-Ready Site”? <ul><li>It matches electric facilities to the proposed use </li></ul><ul><ul><li>Heavy Industrial/High Tech - Sub-transmission or transmission on-site or nearby, dual feed capability, high reliability </li></ul></ul><ul><ul><li>Data Centers - Sub-transmission or transmission on-site or nearby, redundant service capabilities, high reliability </li></ul></ul><ul><ul><li>Light Industrial/ Distribution – Primary or secondary </li></ul></ul><ul><ul><li>Office - Primary or secondary, underground preferred </li></ul></ul><ul><li>Proximity to Electric Facilities - The Closer the Better </li></ul><ul><ul><li>Low or no Customer Charges for Line Extension Costs </li></ul></ul><ul><ul><li>Time Requirements for System Upgrades/ Line Extensions </li></ul></ul>
  20. 20. Who’s Responsible for What? <ul><li>Overhead Distribution Electric Extension (Rule 15) </li></ul><ul><ul><li>NG will install, at its cost, up to 300 feet for a three- phase extension and 500 feet for a single-phase extension </li></ul></ul><ul><ul><li>Customer pays NG costs for footage in excess of 300/500 feet (costs per foot) </li></ul></ul><ul><ul><li>Customer provides right-of-way (ROW) or agrees to pay NG for ROW acquisition </li></ul></ul>
  21. 21. Who’s Responsible for What? <ul><li>Service Laterals - Below 15,000 Volts (Rule 21) </li></ul><ul><ul><li>For overhead service laterals from overhead distribution, NG will install service laterals up to 100 feet </li></ul></ul><ul><ul><ul><li>Customer pays for the portion of service lateral in excess of 100 feet that requires intermediate support </li></ul></ul></ul><ul><ul><li>For underground service laterals from overhead distribution lines </li></ul></ul><ul><ul><ul><li>Customer installs, owns and maintains at their expense the entire service connection (riser pole may or may not be chargeable) </li></ul></ul></ul>
  22. 22. Who’s Responsible for What? <ul><li>For underground service laterals from underground distribution lines or network areas (2400 to 15,000 Volts) </li></ul><ul><ul><li>NG will install, own, and maintain, at its expense, the conduit from distribution system to just inside the curb; to the end of the service lateral. </li></ul></ul><ul><ul><li>Customer is responsible for all conduit on it’s premises, from their distribution facilities. </li></ul></ul>
  23. 23. Who’s Responsible for What? <ul><li>Service Laterals above 15,000 volts </li></ul><ul><ul><li>Customer is responsible for all work and costs to install, operate and maintain the lateral </li></ul></ul><ul><li>Special Services Performed By NG for a Customer </li></ul><ul><ul><li>Customer shall reimburse NG for all costs incurred for requested relocations of NG equipment or facilities to suit the convenience of the customer </li></ul></ul><ul><li>Customer requested additions to NG equipment or facilities beyond those necessary or normally used to serve customer </li></ul><ul><ul><li>Customer pays NG for all costs for the work. Payment can be made by upfront payment or via a monthly surcharge of 1.5% on electric bill for 10 years </li></ul></ul>
  24. 24. Who’s Responsible for What? <ul><li>Underground Distribution Extensions for Non-Residential Developments </li></ul><ul><ul><li>Customer makes advance payment contribution to NG for the amount of the company’s estimated underground extension costs (maximum payment will be the delta of underground estimates to overhead extension estimates) </li></ul></ul><ul><ul><li>If overhead extension cost estimates exceed underground estimates, applicant will pay underground costs. </li></ul></ul>
  25. 25. Who’s Responsible for What? <ul><li>Rule 4.2 – Expansions </li></ul><ul><ul><li>If a customer requests added or enlarged electric facilities to accommodate load increase of 150 kW or greater, for their sole use, NG may require the customer to make a reasonable contribution to the cost of adding or enlarging facility (CIAC – Contribution In Aid to Construction) </li></ul></ul>
  26. 26. The Natural Gas System <ul><li>Production Interstate Pipeline Distribution </li></ul>
  27. 27. Natural Gas Delivery System
  28. 28. Gas Utilities Prior to Deregulation <ul><li>A single, vertically integrated utility company that: </li></ul><ul><ul><li>Produces natural gas </li></ul></ul><ul><ul><ul><li>(owns and operates production) </li></ul></ul></ul><ul><ul><li>Transmits natural gas (owns and operates large transmission pipelines) </li></ul></ul><ul><ul><li>Distributes natural gas </li></ul></ul><ul><ul><ul><li>(owns and operates local distribution pipeline system) </li></ul></ul></ul><ul><ul><li>Provides ancillary services (scheduling and balancing of gas supply) </li></ul></ul><ul><ul><li>Provides metering & billing services </li></ul></ul>
  29. 29. Deregulated Natural Gas Utilities <ul><li>Production Interstate Pipeline Distribution </li></ul>UNREGULATED REGULATED
  30. 30. Natural Gas Terms <ul><li>Gas Load: rate of gas consumption, usually measured in cubic feet or therms (National Grid bills customers in therms consumed) </li></ul><ul><li>Pressure: expressed in PSI – pounds per square inch or PSIG - pounds per square inch gauge </li></ul><ul><li>Volume: expressed in cubic feet </li></ul><ul><li>Flow: expressed in cubic feet per hour </li></ul><ul><li>British Thermal Unit (Btu): The quantity of heat required to raise the temperature of 1 pound of liquid water by 1 degree Fahrenheit at the temperature at which water has its greatest density (approximately 39 degrees Fahrenheit). </li></ul>
  31. 31. Equivalent Values <ul><li>1 cf = 1,000 Btu = .01 Therm </li></ul><ul><li>1 cf = 0.02832 cubic meters </li></ul><ul><li>1Ccf = 100 cf = 100,000 Btu = 1 Therm </li></ul><ul><li>1Mcf = 1,000 cf = 1,000,000 Btu = 10 Therms </li></ul><ul><li>1Mcf =10 Therms = 1 decatherm (dt) = MMBtu = 1.054615 gigajoules (GJ) </li></ul><ul><li>1Mcf = 1,000 cf = 1,000,000 Mcf </li></ul><ul><li>1Bcf = 1,000,000 Mcf </li></ul><ul><li>This table assumes that one cubic foot of gas contains 1,000 Btu. If one cubic foot of gas has a different Btu content, the above table would require a correction factor </li></ul>
  32. 32. Information Needed for a Capacity Assessment and Bill Estimate <ul><li>Minimum </li></ul><ul><ul><li>Site(s) Location (address, intersection or map) </li></ul></ul><ul><ul><li>Connected Load (Mcf/hr) </li></ul></ul><ul><ul><li>Maximum Hourly Load (Mcf/hr) </li></ul></ul><ul><ul><li>Delivery Pressure Required </li></ul></ul><ul><ul><li>Annual Load (Mcf or therms per year) </li></ul></ul><ul><ul><li>Time Frame for Response </li></ul></ul>
  33. 33. Information Needed for Energy Intensive Operations (i.e. glass manufacturing) <ul><li>More Detailed </li></ul><ul><ul><li>Type of Business </li></ul></ul><ul><ul><li>Type of Equipment </li></ul></ul><ul><ul><li>Equipment Use (hours of operation) </li></ul></ul><ul><ul><li>Site Plans </li></ul></ul><ul><ul><li>Actual Site Location </li></ul></ul><ul><ul><li>Service Required Date </li></ul></ul>
  34. 34. Why does the Utility need this information? To Determine the Cost to Serve <ul><li>Short Term </li></ul><ul><ul><li>Determine Available Capacity </li></ul></ul><ul><ul><li>Determine Flow Date </li></ul></ul><ul><ul><li>Measure Impact on System </li></ul></ul><ul><ul><li>Snapshot of Demand on System </li></ul></ul><ul><ul><li>Plan for Growth </li></ul></ul>
  35. 35. Why does the Utility need this information? To Determine the Cost to Serve <ul><li>Long Term </li></ul><ul><li>Determine Upstream Impact </li></ul><ul><li>Determine Downstream’ Impact </li></ul><ul><li>Anticipate System Demands </li></ul><ul><li>Make the best use of time </li></ul>
  36. 36. Why Bring Utility in on Retention/Expansion Opportunities? <ul><li>Determine if impending change will effect service </li></ul><ul><li> Manage Customer and Community Expectations </li></ul><ul><li>Review by gas engineering </li></ul><ul><li>Manage Customer and Community Expectations </li></ul><ul><li>Determine how best to serve </li></ul><ul><li> Manage Customer and Community Expectations </li></ul><ul><li>Determine potential customer charges </li></ul><ul><li>Manage Expectations and Address with Programs </li></ul>
  37. 37. Who’s Responsible for What? <ul><li>Extension of Gas Mains (Rule 10) </li></ul><ul><ul><li>For non-residential customers, NG provides: </li></ul></ul><ul><ul><ul><li>Material and installation costs related to 100 feet of main and appurtenant facilities </li></ul></ul></ul><ul><ul><ul><li>Service line, service connections and appurtenant facilities located in the public right-of way </li></ul></ul></ul><ul><ul><ul><li>Amounts legally imposed for working permits and repairing or replacing disturbed pavement </li></ul></ul></ul>
  38. 38. Who’s Responsible for What? <ul><ul><li>Applicant is responsible for: </li></ul></ul><ul><ul><ul><li>Costs associated with extending gas main beyond 100 feet; and, </li></ul></ul></ul><ul><ul><ul><li>A surcharge which would include return, depreciation, taxes and maintenance of 20% per year of the actual reasonable costs; or </li></ul></ul></ul><ul><ul><ul><li>See next two slides for revenue justification options </li></ul></ul></ul>
  39. 39. Who’s Responsible for What? <ul><li>A surcharge which shall be paid ratably from time of receiving gas service for ten years </li></ul><ul><li>Surcharge will be reduced annually as a credit based on 50% of adjusted gas revenues </li></ul><ul><li>Surcharge will be adjusted if more customers are added to the extension, based on allowed footages per customer </li></ul><ul><li>Surcharges will cease if Adjusted Gas Revenue (AGR) from all customers on extension equal 40% of main costs for two consecutive years </li></ul><ul><li>No surcharge if estimated AGR equals 40% of actual reasonable cost of extension </li></ul>
  40. 40. Who’s Responsible for What? <ul><li>Customer may elect contribution in lieu of surcharge, which is extension cost in excess of allowance, less estimated two year AGR </li></ul><ul><li>When more than one customer is initially connected to an extension, the contribution will be reasonably allocated to all customers </li></ul><ul><li>If customers are added within five years of an extension, a pro-rata refund will be made for that portion of main extension </li></ul><ul><li>If AGR from all customers served by main extension exceed carrying costs of entire extension, any surcharges or contributions paid by such customers during preceding five years will be refunded </li></ul>
  41. 41. Resources <ul><li>Glossary of Utility Terms </li></ul><ul><li>Utility Usage Worksheet </li></ul><ul><li> </li></ul><ul><li>Electric and Gas Industry </li></ul><ul><li>Federal Energy Regulatory Commission http:// / </li></ul><ul><li>Electric Power Research Institute </li></ul><ul><li>Edison Electric Institute (EEI) </li></ul><ul><li>American Gas Association </li></ul><ul><li>Energy Information Administration </li></ul><ul><li>Natural Gas Supply Association </li></ul><ul><li>Public Utilities Reports </li></ul>
  42. 42. Contact National Grid’s Economic Development Department <ul><li>Art Hamlin Director, Economic Development (315) 428 6543 </li></ul><ul><li>Linda Hill (518) 433 3691 </li></ul><ul><li>Brian Anderson (315) 428 5140 </li></ul>Joe Russo (315) 428 6798 Dan Murphy (315) 428 5198 Linda Clark (315) 428 6891 300 Erie Boulevard West Syracuse, NY 13202