NARUC Energy Regulatory Partnership Program The Georgian National Energy Regulatory Commission and

1. Purchased Power Contracts NARUC Energy Regulatory Partnership Program The Georgian National Energy Regulatory Commission and The Vermont Public Service Board by Ann Bishop Vermont Public Service Board June 30, 2008

2. Overview • Background • Vermont electric industry • Regional electric industry • Legal/regulatory framework • Structure of purchased power contracts • Purchased power contracts and retail tariffs

3. Vermont Electric Industry • Vermont has: • 620,000 people; 350,000 electric customers • 9,200 square miles (small, rural state) • 20 electric distribution utilities, including: • 3 investor-owned utilities • 15 municipally-owned utilities • 2 cooperatively-owned utilities • Many electric utilities are very small • Smallest has only 300 customers, and a system peak of less than 0.5 MW • Largest has 150,000 customers, and a system peak of 421 MW

4. Vermont Electric Industry

5. Vermont Electric Industry • Board regulates all electric distribution utilities, and all are vertically integrated • However, utilities own very little generation • There is no retail choice in Vermont (customers cannot choose their electricity supplier) • Vermont has one electric transmission utility • Board has some jurisdiction over this utility • Federal Energy Regulatory Commission (FERC) has jurisdiction over its rates

6. Vermont Electric Industry

7. Regional Electric Industry • Vermont is part of the New England regional competitive wholesale electricity market Vermont

8. Regional Electric Industry • New England has: • 14 million people; 6.5 million electricity customers • 350+ generators/power plants • 8,000 miles of transmission lines • 32,000 MW of total supply • New England regional electricity market is: • Regulated by FERC • Administered by the New England Independent System Operator (ISO-NE)

9. Regional Electric Industry • Regional market participants include: • Generators • Energy efficiency program providers • Demand response providers • Utilities • Other load-serving entities

10. Regional Electric Industry • New England region is summer peaking, with all-time peak of 28,130 MW (in 2006) • Vermont has recently become summer peaking, although some individual utilities are still winter peaking, all-time peak of 1,098 MW (in 2006) • Vermont is approximately 5 percent of the region’s electricity consumption

11. ISO-NE • Not-for-profit corporation created in 1997 to oversee New England’s electric power system • Independent of companies doing business in regional market • Independent Board of Directors with no financial stake in regional energy companies

12. ISO-NE • Three primary responsibilities: • Operate region’s bulk electric power system • Manage wholesale electricity markets • Develop and manage the annual and long-term planning process for the regional electric system

13. Wholesale Power Market Rules • FERC approves rules for wholesale power market; ISO-NE administers the rules • Rules are designed to: • Protect reliability of the transmission grid • Provide for centralized dispatch of generating units • Create efficient competitive markets, including a “level playing field” for all market participants (generators, marketers, transmission owners, energy efficiency providers, etc.) • Create accurate price signals • Provide for market monitoring to prevent abuse of market power

14. Legal/Regulatory Framework • Vermont law requires utilities to plan for, and procure, supply necessary to meet the public’s needs at the lowest present-value life-cycle cost • Supply includes energy efficiency • Vermont law requires regulators to review some purchased power contracts in advance • Regulators may also review existing contracts in rate cases

15. Resource Planning in Vermont • Vermont law requires electric and gas utilities to prepare and implement an Integrated Resource Plan (IRP), which is: “a plan for meeting the public's need for energy services, after safety concerns are addressed, at the lowest present value life cycle cost, including environmental and economic costs, through a strategy combining investments and expenditures on energy supply, transmission and distribution capacity, transmission and distribution efficiency, and comprehensive energy efficiency programs.”

16. Resource Planning in Vermont • An IRP should include: • Load forecasts, both a base case and a case that is adjusted to reflect energy efficiency investments • Identification of committed and available resources (both supply-side and demand-side) • Evaluation of options for improving transmission and distribution efficiency and reliability • Vegetative management plan • Selection of least-cost portfolio, based on an integrated analysis that accounts for uncertainty and contingencies • Effective strategies for implementing the least-cost integrated portfolio identified in the plan • Three-year action plan

17. Resource Planning in Vermont • Electric and gas utilities file IRPs with the Board and the DPS every three years • Board may approve, not approve, or approve with conditions • Approval is of the decision-making processes included in the IRP, but not the specific decision-making tools, analytic methods, or outcomes described in the plan

18. Power Supply Planning Principles • To minimize power supply price risk, it is important for utilities to: • Have a diverse supply portfolio, with a mixture of fuel sources and contract types • Have contracts with staggered expiration dates • Not depend too heavily on any one generator (system power is more reliable)

19. Power Procurement • ISO-NE rules determine the amounts of various electricity-related products that utilities must have • Utilities must purchase enough electricity to meet their load • Rules link required amounts of other products to size of load • For example, ISO-NE calculates each utility’s “load ratio share”; each utility is required to procure that percentage of the total amount of a product required by the region

20. Power Procurement • Utilities are responsible for all steps in power procurement, including: • Issuing requests for proposals, negotiating and executing purchased power contracts • Purchasing power in regional competitive day-ahead or spot energy markets, or long-term forward capacity market • Selling excess power through bilateral contracts or in regional markets • Procuring any necessary transmission services (requirements depend upon contract terms) • Procuring any necessary “ancillary services” • Obtaining any necessary advance regulatory approvals • Continually managing power portfolio

21. Advance Regulatory Approval • Advance Board approval is required for purchases of electric energy or capacity from outside the state for a period exceeding 5 years that represents more than 1 percent of a utility’s historic peak demand • Vermont law specifies criteria to be met • Other purchased power contracts do not require advance Board approval • Contracts to sell power do not require advance Board approval

22. Criteria for Regulatory Approval • Is required to meet the need for present and future demand for service which could not otherwise be provided in a more cost effective manner through energy conservation programs and measures and energy-efficiency and load management measures • Will not adversely affect system stability and reliability • Will result in an economic benefit to the state and its residents

23. Criteria for Regulatory Approval • Is consistent with the principles for resource selection expressed in that utility’s approved IRP • Is in compliance with the electric energy plan prepared by the DPS, or there exists good cause to permit the proposed action • Can be served economically by existing or planned transmission facilities without undue adverse effect on Vermont utilities or customers

24. Regulatory Review of Existing Power Contracts • In a rate case, the Board can consider whether to allow a utility to recover from ratepayers some or all of the costs of an existing purchased power contract • Prudence • Used-and-useful • These tests can be applied once to any contract • Determination can occur at any time during the life of a contract • Once determination is made, it applies for the life of a contract

25. Prudence • Were a utility’s actions, based on all that it knew (or should have known) at the time, reasonable and prudent in light of the circumstances that existed at the time? • Not based on hindsight • Respects the utility’s managerial rights • If not, Board generally will not allow the portion of the costs that it finds were imprudent to be collected from ratepayers

26. Used-and-Useful • Part 1: Is the contract (or investment) used to provide service to ratepayers? • If not, ratepayers should not pay for it • Part 2: Is the contract (or investment) economic for the purposes it is serving? Is it expected to yield net present value benefits, after consideration of non-price benefits, over its lifetime? • If not, the Board will share excess costs between ratepayers and shareholders, as appropriate

27. Regulatory Review of Existing Power Contracts • In a rate case, the Board can also determine whether a utility has appropriately managed its supply portfolio (including power contracts) • If not, Board could reduce utility’s allowed return on equity

28. Structure of Contracts • Contracts can include whatever terms the parties to the contracts agree upon • Some common terms: • Product • Price • Delivery location • Risk management provisions • Length of contract

29. Product • Energy and capacity are the most common products • Other products include “ancillary services” that ISO-NE requires utilities to purchase • Operating reserve • Automatic generation control • Some contracts are unit-specific (products are only provided if a certain unit is operating) while others provide for system power • Resources can supply multiple products • Utilities can purchase products from multiple sources

30. Product • The competitive market uses certain standard energy products • Peak product = “5 x 16” (five weekdays, 16 hours each day) • Off-peak product = “5 x 8, 2 x 24” (five weekdays, 8 hours each day, plus 2 weekend days, 24 hours each day) • Standard products assume delivery at a regional “hub” • Hub is not a physical location; is intended to represent a place with no congestion

31. Product • Market has made prices more transparent • Forward prices are widely available over the internet for the standard products, delivered at a regional hub, for up to 4 years (currently through calendar year 2011) • Prices for delivery at places other than the hub differ due to line losses and congestion costs • Prices at other places can be higher or lower than the hub price • Can use historical data to see relationships between prices at hub and at other delivery points

32. Sample Quote Sheet

33. Energy Price • Per kWh price can be fixed or variable • Most standard contracts base prices on forward market prices • Variable prices are often linked to some type of index • Regional wholesale spot market price • Fuel price • General inflation • Can have floor price, ceiling price, or collar • For example, Vermont utilities’ contract for power from Vermont Yankee includes ceiling price with low-market adjuster • Prices can vary by time of day

34. Capacity Price • Per kW/month price • When wholesale market was first created, price of capacity fell to near zero • Now transitioning to a new auction-based regional capacity market • It is expected that capacity prices will increase to reflect the prices in this market • In the new market: • New resources, including demand resources, set the price • The price is intended to be the cost of new entry • Prices can be fixed for up to 5 years

35. Delivery Location • Important for transmission • If seller is located outside the region, power must be imported • Physical transmission capacity must be contracted to get the power into the region • Either the buyer or seller can do so, depending upon the delivery location specified in the power contract • If seller is located within the region: • Difference between price of power at delivery location and buyer’s location determines “congestion costs” and line losses paid by buyer

36. Risk Management Provisions • Designed to mitigate the risk that a party will fail to meet a contract’s term • Standard requirements exist that are based upon a market participant’s credit rating and the difference between the contract price and the market price • The lower the credit rating, the higher the collateral a market participant could be required to post, depending on market prices • Requirements apply to both buyers and sellers

37. Length of Contract • Historically, long-term contracts of 20 years or more were available • Two-thirds of Vermont’s power is currently provided by two such long-term contracts; these contracts end between 2012 and 2015 • Since the creation of the regional market, short-term contracts are common • Most are less than 3 years • It is rare for a contract to be longer than 5 years

38. Power Contracts and Retail Tariffs • For most Vermont electric distribution utilities, power costs are 60-70%of their total cost of service • The prudent and used-and-useful costs of purchased power contracts are included in utility rates • Under cost-of-service regulation, changes in a utility’s power costs do not change utility rates unless a utility files a complete cost-of-service tariff filing • Some “special contracts” have rates that are tied to a utility’s actual power costs • If a utility is on an alternative regulation plan with a purchased-power adjustment clause, changes in power costs are passed through to customers, typically on a quarterly basis

39. Special Contracts • Utilities must charge tariffed rates, unless the Board approves exceptions for individual customers (known as “special contracts”) • Exceptions to tariffs can be in the public good: • To reflect a customer’s unique circumstances • To keep a customer with the capability to self-generate from leaving the system • To encourage economic development

40. Purchased Power Adjustment Clause • A PPA is a mechanism for allowing a utility to pass through its actual power costs to customers • Many U.S. states allow PPAs; Vermont only allows them if the utility is under alternative regulation • One VT electric utility currently has a PPA; another request is pending before the Board

41. Purchased Power Adjustment Clause • Over the last 10 years, purchased power costs have become more volatile • Under cost-of-service regulation, there is always “regulatory lag” because rates are set on a going-forward basis using historic costs (adjusted for known and measurable changes) • PPAs greatly reduce this regulatory lag and provide greater certainty to a utility that it will be able to collect its actual power costs

42. Purchased Power Adjustment Clause • Lower utility risk should lead to a lower return on equity for a utility with a PPA • A PPA does shift risk to customers and can result in greater rate volatility